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What changed in PG&E Corporation's 10-K — 2022 vs 2023

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Paragraph-level year-over-year comparison of PG&E Corporation's 2022 and 2023 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2023 report.

+712 added−858 removedSource: 10-K (2024-02-22) vs 10-K (2023-02-23)

Top changes in PG&E Corporation's 2023 10-K

712 paragraphs added · 858 removed · 527 edited across 8 sections

Item 1. Business

Business — how the company describes what it does

185 edited+38 added−33 removed116 unchanged
Biggest changeAs a result of actions already taken by PG&E Corporation and the Utility, the companies have: • Delivered clean electricity to customers in 2022 that was more than 95% GHG free. • Helped customers avoid emissions and energy costs through robust energy efficiency programs. • Awarded contracts for more than 3.3 GWs of battery energy storage to be deployed over the next several years, strengthening California’s grid efficiency and reliability. • Installed approximately 340 charging ports for electric vehicles at schools, parks, public charging locations, and in support of fleets - with nearly half in disadvantaged communities - and received regulatory approval for new innovative pilots on vehicle grid integration, submetering, and dynamic rates. • Brought the total number of interconnected private solar customers to more than 700,000 and supported more than 50,000 customers who have installed battery storage at their homes or businesses. • Continued to advance decarbonization initiatives for the Utility’s natural gas delivery system, including meeting the CPUC-mandated methane emission reduction target ahead of schedule and accelerating initiatives to meet its voluntary 2030 reduction goal. 13 The CPUC coordinates the planning of supply resources through the Integrated Resource Planning (“IRP”) proceeding and has determined that replacing the power generated by Diablo Canyon is the responsibility of all LSEs within the CAISO.
Biggest changeAs a result of actions already taken by PG&E Corporation and the Utility, the companies have: • Delivered electricity to customers in 2023 that was 100% GHG free (see “Electricity Resources” below for more information). • Helped customers avoid emissions and manage energy costs through robust energy efficiency programs. • Managed contracts for more than 3.5 GW of battery energy storage to be deployed over the next several years and operated 183 MW of Utility-owned battery storage, strengthening California’s grid efficiency and reliability. • Helped enable the total number of electric vehicles operating in the Utility’s service area to exceed 550,000; installed more than 475 charging ports for electric vehicles at schools, public charging locations, and in support of fleets; and launched a first of its kind vehicle-to-grid program enabling customers to leverage their electric vehicles to power their home. • Brought the total number of interconnected private solar customers to more than 800,000 and supported more than 70,000 customers who have installed battery storage at their homes or businesses. • Continued to advance decarbonization initiatives for the Utility’s natural gas delivery system, including meeting the CPUC-mandated methane emission reduction target ahead of schedule and accelerated initiatives to meet its voluntary 2030 reduction goal.
The Utility is also subject to the requirements of other federal, state and local regulatory agencies, including with respect to safety, the environment, and health, such as the NTSB and OEIS. This section and the “Environmental Regulation” and the “Ratemaking Mechanisms” sections below summarize some of the more significant laws, regulations, and regulatory proceedings affecting the Utility.
The Utility is also subject to the requirements of other federal, state and local regulatory agencies, including with respect to safety, the environment, and health, such as the NTSB and the OEIS. This section and the “Environmental Regulation” and the “Ratemaking Mechanisms” sections below summarize some of the more significant laws, regulations, and regulatory proceedings affecting the Utility.
These agreements are governed by the FERC-approved tariffs that detail rates, rules, and terms of service for the provision of natural gas transportation services to the Utility on interstate and Canadian pipelines.
These agreements are governed by FERC-approved tariffs that detail rates, rules, and terms of service for the provision of natural gas transportation services to the Utility on interstate and Canadian pipelines.
As of December 31, 2022, the Utility was on track to meet its storage goals by the end of 2024. Additionally, the Utility has been actively procuring energy storage to meet critical reliability needs. The CPUC previously approved more than 1,100 MW of storage to come online in 2022 and 2023.
As of December 31, 2023, the Utility was on track to meet its storage goals by the end of 2024. Additionally, the Utility has been actively procuring energy storage to meet critical reliability needs. The CPUC previously approved more than 1,100 MW of storage to come online in 2022 and 2023.
As the Utility’s asset inspections have identified more equipment conditions, the Utility has hardened its system by correcting significantly more equipment conditions than in prior years. Hardening methods include replacing bare overhead conductor with covered conductor and installing stronger poles, removing lines, and serving customers through remote grids, or converting lines from overhead to underground.
As the Utility’s asset inspections have identified more equipment conditions, the Utility has hardened its system by correcting significantly more equipment conditions than in prior years. Hardening methods also include replacing bare overhead conductor with covered conductor and installing stronger poles, removing lines, and serving customers through remote grids, or converting lines from overhead to underground.
Under the current gas and electric citation programs adopted by the CPUC in September 2016, the SED has discretion whether to issue a penalty for each violation; but if it assesses a penalty for a violation, it has the authority to impose the maximum statutory penalty of $100,000 per day, with an administrative limit of $8 million per citation issued.
Under the current gas and electric citation programs adopted by the CPUC in September 2016, the SED has discretion whether to issue a penalty for each violation. If it assesses a penalty for a violation, it has the authority to impose the maximum statutory penalty of $100,000 per day, with an administrative limit of $8 million per citation issued.
The triple bottom line is designed to balance the interests of the companies’ many stakeholders, and it reflects the broader societal impacts of the companies’ activities. PG&E Corporation and the Utility will continue to consider the impact on the triple bottom line of people, planet, and prosperity in their daily operations as well as in their long-term strategic decisions.
The triple bottom line is designed to balance the interests of the companies’ many stakeholders, and it reflects the broader societal impacts of the companies’ activities. 11 PG&E Corporation and the Utility will continue to consider the impact on the triple bottom line of people, planet, and prosperity in their daily operations as well as in their long-term strategic decisions.
After EPSS was initiated, both the size and number of CPUC-reportable ignitions were reduced substantially on EPSS-enabled circuits, compared to the prior three-year average. 15 • Public Safety Power Shutoffs: The PSPS program proactively de-energizes power lines in response to forecasted weather conditions.
After EPSS was initiated, both the size and number of CPUC-reportable ignitions were reduced substantially on EPSS-enabled circuits, compared to the prior three-year average. • Public Safety Power Shutoffs: The PSPS program proactively de-energizes power lines in response to forecasted weather conditions.
In addition to updating the CVA, the Utility regularly reviews relevant scientific literature regarding climate change to incorporate appropriate information into its operations. For example, based on a recent report about potential major atmospheric river events, the Utility updated and modified its flooding emergency response plan.
In addition to updating the CVA, the Utility regularly reviews relevant scientific literature regarding climate change to incorporate appropriate information into its operations. For example, based on a report about potential major atmospheric river events, the Utility updated and modified its flooding emergency response plan.
In addition, employees are required to complete an annual compliance and ethics training and a Code of Conduct training, both of which are intended to promote a culture in which employees are encouraged to speak up with any concerns or ideas for continuous improvement. In addition, the Utility offers a variety of other trainings and education opportunities.
In addition, employees are required to complete annual compliance and ethics training and a Code of Conduct training, both of which are intended to promote a culture in which employees are encouraged to speak up with any concerns or ideas for continuous improvement. In addition, the Utility offers a variety of other trainings and education opportunities.
To meet their longer-term climate goals, PG&E Corporation and the Utility intend to scale their efforts to decarbonize the electric system to accommodate a shift to vehicle electrification, integrate a proliferation of distributed energy resources, and achieve increased penetration of renewable energy combined with investments in the grid and energy storage.
To meet their longer-term climate goals, PG&E Corporation and the Utility intend to scale their efforts to decarbonize the energy system to accommodate a shift to vehicle electrification, integrate a proliferation of distributed energy resources, and achieve increased penetration of renewable energy combined with investments in the grid and energy storage.
The Utility also delivers gas to off-system customers (i.e., outside of the Utility’s service area) and to third-party natural gas storage customers. 32 Natural Gas Supplies The Utility can receive natural gas from all the major natural gas basins in western North America, including basins in western Canada, the Rocky Mountains, and the southwestern United States.
The Utility also delivers gas to off-system customers (i.e., outside of the Utility’s service area) and to third-party natural gas storage customers. Natural Gas Supplies The Utility can receive natural gas from all the major natural gas basins in western North America, including basins in western Canada, the Rocky Mountains, and the southwestern United States.
The Utility’s assets on the coast and in or near watersheds face potential increased exposures to coastal, riverine, and precipitation-related flooding because of climate-driven changes in precipitation and sea-level rise. Climate change will also continue to intensify the potential for wildfires throughout California.
The Utility’s assets on the coast and in or near watersheds face potential increased exposures to coastal, riverine, and precipitation-related flooding because of climate-driven changes in precipitation and sea-level rise. 12 Climate change will also continue to intensify the potential for wildfires throughout California.
As a result of the improved inspection program, the Utility’s inspections in recent years have begun to more thoroughly identify equipment conditions. • System hardening: System hardening entails repairing, replacing, or eliminating existing power lines in HFTDs and installing stronger and more resilient equipment.
As a result of the improved inspection program, the Utility’s inspections in recent years have begun to more thoroughly identify equipment conditions. 15 • System hardening: System hardening entails repairing, replacing, or eliminating existing power lines in HFTDs and installing stronger and more resilient equipment.
The Utility, as the CPE, will not be assessed fines or penalties for failing to procure resources to meet the local RA requirements and deferring local procurement to the CAISO backstop mechanism, as long as the CPE exercised reasonable efforts to secure capacity and certain specified requirements are met.
The Utility, as the CPE, will not be assessed fines or penalties for failing to procure resources to meet the local RA requirements and deferring local procurement to the CAISO backstop mechanism, so long as the CPE exercised reasonable efforts to secure capacity and certain specified requirements are met.
A key element of preparing the Utility for the physical risks of climate change is an updated and more detailed system-wide CVA of the Utility’s assets, operations, and services, which the Utility expects to file with the CPUC in 2024.
A key element of preparing the Utility for the physical risks of climate change is an updated and more detailed system-wide CVA of the Utility’s assets, operations, and services, which the Utility expects to file with the CPUC in mid-2024.
The CPUC enforces state laws and regulations that set forth safety requirements pertaining to the design, construction, testing, operation, and maintenance of utility gas and electric facilities. The CPUC can impose penalties of up to $100,000 per day, per violation.
The CPUC enforces state and federal laws and regulations that set forth safety requirements pertaining to the design, construction, testing, operation, and maintenance of utility gas and electric facilities. The CPUC can impose penalties of up to $100,000 per day, per violation.
The Utility has franchise agreements with approximately 300 cities and counties that permit the Utility to install, operate, and maintain the Utility’s electric and natural gas facilities in the public streets and highways. In exchange for the right to use public streets and highways, the Utility pays annual fees to the cities and counties.
The Utility has franchise agreements with approximately 300 cities and counties that permit the Utility to install, operate, and maintain the Utility’s electric or natural gas facilities in the public streets and highways. In exchange for the right to use public streets and highways, the Utility pays annual fees to the cities and counties.
The Utility’s preparations for the physical risks of climate change include an updated, more detailed, system‑wide CVA of the Utility’s assets, operations, and services, which will be completed in 2024 and filed with the CPUC.
The Utility’s preparations for the physical risks of climate change include an updated, more detailed, system‑wide CVA of the Utility’s assets, operations, and services, which will be completed and filed with the CPUC in mid-2024.
The Utility will continue to seek fair and timely regulatory treatment in order to support its customer-driven investment plan while pursuing cost-control measures that would allow it to maintain the affordability of its service. The Lean operating system is an important means of realizing PG&E Corporation’s and the Utility’s objective of achieving world class performance while delivering hometown service.
The Utility will continue to seek fair and timely regulatory treatment to support its customer-driven investment plan while pursuing cost-control measures that would allow it to maintain the affordability of its service. The Lean operating system is an important means of realizing PG&E Corporation’s and the Utility’s objective of achieving world-class performance while delivering hometown service.
PG&E Corporation’s and the Utility’s performance is also driven by an increased focus on alignment on shared outcomes among its leadership and within the organization.
PG&E Corporation’s and the Utility’s performance is also driven by an increased focus on alignment of shared outcomes among its leadership and within the organization.
The FERC has authority to impose fines of up to $1 million per day for violations of certain federal statutes and regulations. For more information on specific FERC requirements and their impact on PG&E Corporation and the Utility, see Item 1A. Risk Factors, and “Regulatory Matters,” “Legislative and Regulatory Initiatives” and “Liquidity and Financial Resources” in Item 7.
The FERC has authority to impose fines of up to $1 million per day for violations of certain federal statutes and regulations. For more information on specific FERC requirements and their impact on PG&E Corporation and the Utility, see Item 1A. Risk Factors, and “Regulatory Matters,” “Legislative and Regulatory Initiatives,” and “Liquidity and Financial Resources” in Item 7.
The Utility recovers its electric procurement costs annually primarily through balancing accounts. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8. Each year, the CPUC reviews the Utility’s forecasted procurement costs related to power purchase agreements, derivative instruments, GHG emissions costs, and generation fuel expense, and approves a forecasted revenue requirement.
The Utility recovers its electric procurement costs annually primarily through balancing accounts. See Note 3 of the Notes to the Consolidated Financial Statements in Item 8. Each year, the CPUC reviews the Utility’s forecasted procurement costs related to power purchase agreements, derivative instruments, GHG emissions costs, and generation fuel expense, and approves a forecasted revenue requirement.
The Utility conducts an annual employee engagement survey to measure and improve employee engagement progress. Every year, PG&E Corporation and the Utility offer or require technical, leadership, and employee training, which includes a range of technical training for employees on the knowledge and skills required to perform their jobs safely using approved tools and work procedures.
The Utility conducts an annual employee survey to measure and improve employee engagement. 27 Every year, PG&E Corporation and the Utility offer or require technical, leadership, and employee training, which includes a range of technical training for employees on the knowledge and skills required to perform their jobs safely using approved tools and work procedures.
MD&A and Note 16 of the Notes to the Consolidated Financial Statements in Item 8. The CAISO is the FERC-approved regional transmission organization for the Utility’s service area. The CAISO controls the operation of the electric transmission system in most of California and a small part of Nevada and provides open access transmission service on a non-discriminatory basis.
MD&A and Note 15 of the Notes to the Consolidated Financial Statements in Item 8. The CAISO is the FERC-approved regional transmission organization for the Utility’s service area. The CAISO controls the operation of the electric transmission system in most of California and a small part of Nevada and provides open access transmission service on a non-discriminatory basis.
Generally, the Utility recovers most of the costs of complying with environmental laws and regulations through the Utility’s rates, subject to reasonableness review. Environmental costs associated with the clean-up of most sites that contain hazardous substances are subject to a ratemaking mechanism described in Note 16 of the Notes to the Consolidated Financial Statements in Item 8.
Generally, the Utility recovers most of the costs of complying with environmental laws and regulations through the Utility’s rates, subject to reasonableness review. Environmental costs associated with the clean-up of most sites that contain hazardous substances are subject to a ratemaking mechanism described in Note 15 of the Notes to the Consolidated Financial Statements in Item 8.
(For more information regarding the Utility’s natural gas transportation agreements, see Note 16 of the Notes to the Consolidated Financial Statements in Item 8.) The Utility owns and operates three underground natural gas storage fields and has a 25% interest in a fourth storage field, all of which are connected to the Utility’s gas transmission system.
(For more information regarding the Utility’s natural gas transportation agreements, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8.) The Utility owns and operates three underground natural gas storage fields and has a 25% interest in a fourth storage field, all of which are connected to the Utility’s gas transmission system.
The CPUC has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the gravity of the violations, the type of harm caused by the violations and the number of persons affected, and the good faith of the entity charged in attempting to achieve compliance, after notification of a violation.
The CPUC has broad discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the gravity of the violations, the type of harm caused by the violations and the number of persons affected, and the good faith of the entity charged in attempting to achieve compliance, after notification of a violation.
Climate Change Resilience Strategies Mitigating Greenhouse Gas Emissions During 2022, the Utility continued its programs to mitigate the impact of the Utility’s operations (including customer energy usage) on the environment, consistent with the Utility’s commitment to a healthy environment and carbon neutral-energy system for all Californians.
Climate Change Resilience Strategies Mitigating Greenhouse Gas Emissions During 2023, the Utility continued its programs to mitigate the impact of the Utility’s operations (including customer energy usage) on the environment, consistent with the Utility’s commitment to a healthy environment and carbon neutral-energy system for all Californians.
Peak electric loads are expected to increase with increasing temperatures due to direct impacts of ambient temperatures on equipment and direct impacts on electricity demand driven by rising air conditioning installation and usage, and increasingly driven in the future from widespread progress in adoption of beneficial electrification technologies.
Peak electric loads are expected to increase with increasing temperatures due to direct impacts of ambient temperatures on equipment and direct impacts on electricity demand driven by rising air conditioning installation and usage, and increasingly driven in the future from widespread progress in adoption of strategic electrification technologies.
Of the Utility’s regular employees, approximately 16,000 are covered by collective bargaining agreements with the local chapters of three labor unions: the International Brotherhood of Electrical Workers (“IBEW”) Local 1245; the Engineers and Scientists of California (“ESC”) IFPTE 20; and the Service Employees International Union Local 24/7 (“SEIU”).
Of the Utility’s regular employees, approximately 17,000 are covered by collective bargaining agreements with the local chapters of three labor unions: the International Brotherhood of Electrical Workers (“IBEW”) Local 1245; the Engineers and Scientists of California (“ESC”) IFPTE 20; and the Service Employees International Union Local 24/7 (“SEIU”).
In order to set rates, the CPUC and the FERC conduct proceedings to determine the amount that the Utility will be authorized to collect from its customers (“revenue requirements”). In the GRC proceedings, the CPUC also generally approves the level of capital spending on a forecasted basis.
To set rates, the CPUC and the FERC conduct proceedings to determine the amount that the Utility will be authorized to collect from its customers (“revenue requirements”). In the GRC proceedings, the CPUC also generally approves the level of spending on a forecasted basis.
Recovery of the costs tracked in these memorandum accounts in rates requires CPUC authorization in separate proceedings for which the Utility may be unable to predict the outcome. Alternatively, the Utility may seek authority to track incremental costs related to these non-GRC programs in balancing accounts.
Recovery of the costs tracked in these memorandum accounts through rates requires CPUC authorization in separate proceedings, the outcome of which the Utility may be unable to predict. Alternatively, the Utility may seek authority to track incremental costs related to these non-GRC programs in balancing accounts.
PG&E Corporation’s and the Utility’s executive teams meet regularly to discuss and evaluate the state of employee talent, determine which programs are driving engagement and performance, and clarify the specific skills, behaviors, and values that should be cultivated. Each year, the Utility honors employees whose work embodies safety, diversity, equity, inclusion, belonging, environmental leadership, and community service.
PG&E Corporation’s and the Utility’s executive teams meet regularly to discuss and evaluate the state of employee talent, determine which programs are driving engagement and performance, and clarify the specific skills, behaviors, and virtues that should be cultivated. Each year, the Utility honors employees whose work embodies safety, diversity, equity, inclusion, belonging, environmental leadership, innovation, and community service.
When the Utility provides both transportation and procurement services, the Utility refers to the combined service as “bundled” natural gas service. More than 96% of core customers, representing approximately 85% of the annual core market demand, receive bundled natural gas service from the Utility.
When the Utility provides both transportation and procurement services, the Utility refers to the combined service as “bundled” natural gas service. More than 96% of core customers, representing approximately 84% of the annual core market demand, receive bundled natural gas service from the Utility.
The Utility is responsible for scheduling and bidding electric generation resources, including certain electricity procured from third parties into the wholesale market, to meet customer demand. 28 The following table shows the percentage of the Utility’s estimated total net deliveries of electricity to customers in 2022 represented by each major electric resource, and further discussed below.
The Utility is responsible for scheduling and bidding electric generation resources, including certain electricity procured from third parties into the wholesale market, to meet customer demand. The following table shows the percentage of the Utility’s estimated total net deliveries of electricity to customers in 2023 represented by each major electric resource, and further discussed below.
The CPUC has approved various power purchase agreements that the Utility has entered into with third parties in accordance with the Utility’s CPUC-approved BPP, to meet mandatory renewable energy targets, and to comply with RA requirements.
The CPUC has approved various power purchase agreements into which the Utility has entered with third parties in accordance with the Utility’s CPUC-approved BPP, to meet mandatory renewable energy targets, and to comply with RA requirements.
(PG&E Corporation and the Utility define retirement age as 55 years and older.) The Utility’s contractors and subcontractors include approximately 42,000 individuals from approximately 1,200 contractor companies. Human Capital Management PG&E Corporation’s and the Utility’s human capital resource objectives are to build and retain an engaged, well trained, diverse, and equitable workforce.
(PG&E Corporation and the Utility define retirement age as 55 years and older.) The Utility’s contractors and subcontractors include approximately 30,000 individuals from approximately 1,000 contractor companies. Human Capital Management PG&E Corporation’s and the Utility’s human capital resource objectives are to build and retain an engaged, well trained, diverse, and equitable workforce.
The principal executive offices of PG&E Corporation and the Utility are located at 300 Lakeside Drive, Oakland, California 94612. PG&E Corporation’s telephone number is (415) 973-1000 and the Utility’s telephone number is (415) 973-7000. This is a combined Annual Report on Form 10-K for PG&E Corporation and the Utility.
The principal executive offices of PG&E Corporation and the Utility are located at 300 Lakeside Drive, Oakland, California 94612. PG&E Corporation’s telephone number is (415) 973-1000 and the Utility’s telephone number is (415) 973-7000. This is a combined Annual Report on Form 10-K for PG&E Corporation and the Utility. Each of PG&E Corporation and the Utility is a separate entity.
The collective bargaining agreements in effect for the IBEW Local 1245; ESC Local 20; and SEIU, United Service Workers West will expire on December 31, 2025. The agreements increase wages annually by 3.75% from 2022 through 2025 and maintain current contributions to specified benefits.
The collective bargaining agreements in effect for the IBEW Local 1245, ESC Local 20, and SEIU United Service Workers West, are set to expire on December 31, 2025. The agreements increase wages annually by 3.75% from 2022 through 2025 and maintain current contributions to specified benefits.
In addition, the Utility uses multiple weather models on a daily basis that indicate which circuits to enable with safety settings and which to put in normal protection settings, optimizing for maximum wildfire ignition risk reduction when needed and enhancing reliability benefits when wildfire risk is low.
In addition, the Utility uses multiple weather models on a daily basis that indicate which circuits to enable with safety settings and which to put in normal protection settings, optimizing for wildfire risk reduction when needed and enhancing reliability when wildfire risk is low.
Parties in the Utility’s GRC include the Public Advocates Office of the CPUC (formerly known as Office of Ratepayer Advocates or ORA) and TURN, which generally represent the overall interests of residential customers, as well as numerous intervenors that represent other business, community, customer, environmental, and union interests.
Parties to the Utility’s GRC include the Public Advocates Office of the CPUC (formerly known as Office of Ratepayer Advocates or ORA) and TURN, which generally represent the interests of residential customers, as well as numerous intervenors that represent other business, community, customer, environmental, and union interests.
Section 387 of the Public Utilities Code allows for a request to transfer the responsibilities of the provider of last resort obligation from IOUs to other entities. 34 The Utility is also impacted by the increasing viability of distributed generation and energy storage.
Section 387 of the Public Utilities Code allows for a request to transfer the responsibilities of the provider of last resort obligation from IOUs to other entities. 34 The Utility is also impacted by an increasing quantity of distributed generation and energy storage.
Among other programs, the Utility provides career opportunities through its PowerPathway™ workforce development program. Launched in 2008, PowerPathway is a workforce development model to enlarge the talent pool of local, qualified, diverse candidates for skilled craft and utility industry jobs through training program partnerships with educational, community-based and government organizations.
In 2023, the Utility significantly expanded its training for supervisors. Among other programs, the Utility provides career opportunities through its PowerPathway™ workforce development program. Launched in 2008, PowerPathway is a workforce development model to enlarge the talent pool of local, qualified, diverse candidates for skilled craft and utility industry jobs through training program partnerships with educational, community-based and government organizations.
To build resilience to these hazards, the Utility is working to systematically integrate the consideration of forward-looking climate data and tools in its decision-making. PG&E Corporation and the Utility also work with policymakers and regulators to advance effective climate adaptation policy in California, and work directly with local governments and communities on adaptation solutions.
To build resilience to these hazards, the Utility is working to systematically integrate forward-looking climate data and tools into its decision-making. PG&E Corporation and the Utility also work with policymakers and regulators to advance effective climate change policy in California, and work directly with local governments and communities on adaptation solutions.
For more information about costs incurred to comply with government regulations and related material effects on PG&E Corporation and the Utility, see Item 1A. Risk Factors, “Regulatory Matters” in Item 7. MD&A, and Notes 15 and 16 of the Notes to the Consolidated Financial Statements in Item 8.
For more information about costs incurred to comply with government regulations and related material effects on PG&E Corporation and the Utility, see Item 1A. Risk Factors, “Liquidity and Financial Resources” and “Regulatory Matters” in Item 7. MD&A, and Notes 14 and 15 of the Notes to the Consolidated Financial Statements in Item 8.
For more information about environmental remediation liabilities, see Note 16 of the Notes to the Consolidated Financial Statements in Item 8.
For more information about environmental remediation liabilities, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8.
In the past few years, the Utility’s electric distribution system has experienced multiple major outage-causing events associated with extreme heat events and peak loads. Peak loads are expected to increase with increasing temperatures due to direct impacts of ambient temperatures on equipment and direct impacts on electricity demand driven by rising air conditioning installation and usage.
In the past few years, the Utility’s electric distribution system has experienced multiple major outage-causing events associated with extreme heat events and peak loads. Peak loads are expected to increase with increasing temperatures due to direct impacts of ambient temperatures on equipment, increased electricity demand driven by rising air conditioning installation and usage, and continued electrification of transportation and buildings.
The Utility is conducting regional community engagement campaigns throughout its service area to understand how some of the most vulnerable communities the Utility serves think about climate hazards and adaptation. This information will help the Utility plan adaptive climate action aligned with customer and community perspectives.
The Utility has conducted regional community engagement campaigns throughout its service area to understand how some of the most vulnerable communities the Utility serves think about climate hazards and adaptation. This information will help the Utility plan adaptive climate action aligned with customer and community perspectives.
PG&E Corporation and the Utility have committed to helping heal the planet. PG&E Corporation’s and the Utility’s Climate Strategy Report, which is available to the public, describes the companies’ climate goals and plans to meet those goals.
PG&E Corporation and the Utility are also committed to helping heal the planet. PG&E Corporation’s and the Utility’s Climate Strategy Report, which is available to the public, describes the companies’ climate goals and plans to meet those goals.
The NRC operating licenses currently expire in 2024 and 2025, respectively. For more information, see “Extension of Diablo Canyon Operations” in Item 7. MD&A below. (2) The Utility’s hydroelectric system consists of 102 generating units at 63 powerhouses.
The NRC operating licenses currently expire in 2024 and 2025, respectively. For more information, see “Extension of Diablo Canyon Operations” in Item 7. MD&A below. (2) The Utility’s hydroelectric system consists of 99 generating units at 61 powerhouses.
Risk Factors and “Regulatory Matters - OIR to Revisit Net Energy Metering Tariffs” in Item 7. MD&A. Further, in some circumstances, governmental entities such as cities and irrigation districts may have authority under the state constitution or state statute to provide retail electric service directly to consumers.
Risk Factors and “Regulatory Matters - OIR to Revisit Net Energy Metering Tariffs” in Item 7. MD&A. Further, in some circumstances, governmental entities such as cities and irrigation districts may have authority under the state constitution or state statute to provide retail electric service directly to consumers, in some cases bypassing the Utility’s electric infrastructure entirely.
PG&E Corporation and the Utility also publish air emissions data in their annual Corporate Sustainability Report. 2021 2020 Total NOx emissions (tons) 139 141 NOx emissions rate (pounds/MWh) 0.01 0.01 Total SO 2 emissions (tons) 14 15 SO 2 emissions rate (pounds/MWh) 0.001 0.001 22 Nuclear Fuel Disposal Nuclear power plant operations produce gaseous, liquid, and solid radioactive wastes, which are covered by federal regulation.
PG&E Corporation and the Utility also publish air emissions data in their annual Corporate Sustainability Report. 2022 2021 Total NOx emissions (tons) 121 139 NOx emissions rate (pounds/MWh) 0.01 0.01 Total SO 2 emissions (tons) 11 14 SO 2 emissions rate (pounds/MWh) 0.001 0.001 22 Nuclear Fuel Disposal Nuclear power plant operations produce gaseous, liquid, and solid radioactive wastes, which are covered by federal regulation.
In 2022, the Utility continued to refine its risk modeling, including further incorporating data from asset inspections.
In 2023, the Utility continued to refine its risk modeling, including further incorporating data from asset inspections.
The Utility reflects the difference between actual natural gas purchase costs and forecasted natural gas purchase costs in several natural gas balancing accounts, with under-collections and over-collections taken into account in subsequent monthly rate changes. The CPIM protects the Utility against after-the-fact reasonableness reviews of its gas procurement costs for its core gas portfolio.
The Utility reflects the difference between actual natural gas purchase costs and forecasted natural gas purchase costs in several natural gas balancing accounts, with adjustments for under-collections and over-collections made in subsequent monthly rate changes. The CPIM protects the Utility against after-the-fact reasonableness reviews of its gas procurement costs for its core gas portfolio.
For costs related to AROs see “Asset Retirement Obligations” in Note 3 of the Notes to the Consolidated Financial Statements in Item 8. 26 Human Capital Employees and Contractors As of December 31, 2022, PG&E Corporation had 10 employees and the Utility had approximately 26,000 regular employees.
For costs related to AROs, see “Asset Retirement Obligations” in Note 2 of the Notes to the Consolidated Financial Statements in Item 8. Human Capital Employees and Contractors As of December 31, 2023, PG&E Corporation had 10 employees and the Utility had approximately 28,000 regular employees.
Natural Gas System Assets The Utility owns and operates an integrated natural gas transmission, storage, and distribution system that includes most of northern and central California. At December 31, 2022, the Utility’s natural gas system consisted of approximately 44,000 miles of distribution pipelines, over 6,300 miles of backbone and local transmission pipelines, and various storage facilities.
Natural Gas System Assets The Utility owns and operates an integrated natural gas transmission, storage, and distribution system that includes most of northern and central California. At December 31, 2023, the Utility’s natural gas system consisted of approximately 44,200 miles of distribution pipelines, over 6,400 miles of backbone and local transmission pipelines, and various storage facilities.
In response, the Utility has implemented operational changes and investments that reduce wildfire risk, including: • Enhanced Powerline Safety Settings: EPSS adjusts the sensitivity of circuit protection devices on selected power lines to de-energize them more rapidly in the event of a disturbance to help prevent potential ignitions.
In response, the Utility has implemented operational changes and investments that reduce wildfire risk, including: • Enhanced Powerline Safety Settings: EPSS adjusts the sensitivity of circuit protection devices on selected power lines to de-energize them in less than one-tenth of a second in the event of a disturbance to help prevent potential ignitions.
During 2022, the Utility purchased approximately 296,000 MMcf of natural gas (net of the sale of excess supply of gas). Substantially all of this natural gas was purchased under contracts with a term of one year or less. The Utility’s largest individual supplier represented approximately 47% of the total natural gas volume the Utility purchased during 2022.
During 2023, the Utility purchased approximately 299,000 MMcf of natural gas (net of the sale of excess supply of gas). Substantially all of this natural gas was purchased under contracts with a term of one year or less. The Utility’s largest individual supplier represented approximately 54% of the total natural gas volume the Utility purchased during 2023.
The levels of self-generation of electricity by customers (primarily solar installations) and customer enrollment in NEM, which allows self-generating customers employing qualifying renewable resources to receive bill credits at the full retail rate, are increasing, putting upward rate pressure on remaining customers.
The levels of self-generation of electricity by customers (primarily solar installations) and customer enrollment in NEM, which allows self-generating customers employing qualifying renewable resources to receive bill credits at the full retail rate, put upward rate pressure on non-NEM customers.
Nuclear Regulatory Commission The NRC oversees the licensing, construction, operation and decommissioning of nuclear facilities, including the Utility’s two nuclear generating units at Diablo Canyon and the Utility’s retired nuclear generating unit at Humboldt Bay. See “Electricity Resources” below. NRC regulations require extensive monitoring and review of the safety, radiological, seismic, environmental, and security aspects of these facilities.
Nuclear Regulatory Commission The NRC oversees the licensing, construction, operation, and decommissioning of nuclear facilities, including the Utility’s two nuclear generating units at Diablo Canyon and the Utility’s independent spent fuel storage installation at Humboldt Bay. See “Electricity Resources” below. NRC regulations require extensive monitoring and review of the safety, radiological, seismic, environmental, and security aspects of these facilities.
As a result, the Utility’s base revenues are not impacted by fluctuations in sales resulting from, for example, weather or economic conditions. The Utility’s earnings primarily depend on its ability to manage its base operating and capital costs (referred to as “Utility Revenues and Costs that Impacted Earnings” in Item 7. MD&A) within its authorized base revenue requirements.
As a result, the Utility’s base revenues are not impacted by fluctuations in sales resulting from, for example, weather or economic conditions. The Utility’s earnings primarily depend on its ability to manage its base operating and capital costs within its authorized base revenue requirements.
Key elements of PG&E Corporation’s and the Utility’s approach include active programming to heighten cultural competency, encourage understanding and appreciation of diversity, and integrate thoughtful content into training and performance support materials.
Key elements of PG&E Corporation’s and the Utility’s approach include active programming to heighten cultural awareness, encourage understanding and appreciation of diversity, and integrate thoughtful content into training, development, and performance support resources.
Similar to penalties imposed by the CPUC, penalty payments for citations issued pursuant to the gas and electric safety citation programs are the responsibility of shareholders of an issuer and may not be recovered in rates or otherwise directly or indirectly charged to customers.
Similar to penalties imposed by the CPUC, penalty payments for citations issued pursuant to the gas and electric safety citation programs are the responsibility of shareholders and may not be recovered through rates or otherwise charged to customers.
Differences in costs can also arise from changes in laws and regulations at both the state and federal level. PG&E Corporation and the Utility are committed to taking steps to improve their credit ratings and metrics over time, including by reducing their debt.
Differences in costs can also arise from changes in laws and regulations at both the state and federal level. PG&E Corporation and the Utility are committed to taking steps to improve their credit ratings and metrics over time, including by reducing PG&E Corporation’s debt by at least $2 billion by the end of 2026.
The Utility’s distribution network interconnects with its transmission system, primarily at switching and distribution substations, where equipment reduces the high-voltage transmission voltages to lower voltages, ranging from 44 kV to 2.4 kV, suitable for distribution to the Utility’s customers. These distribution substations serve as the central hubs for the Utility’s electric distribution network.
The Utility’s distribution network interconnects with its transmission system, primarily at switching and distribution substations, where equipment reduces the high-voltage transmission voltages to lower voltages, suitable for distribution to the Utility’s customers. These distribution substations serve as the central hubs for the Utility’s electric distribution network.
MD&A for more information on specific CPUC proceedings. 23 Base Revenues General Rate Cases The GRC is the primary proceeding in which the CPUC determines the amount of base revenue requirements that the Utility is authorized to collect from customers to recover the Utility’s anticipated costs related to its electric distribution, natural gas distribution, and Utility-owned electric generation operations and return on rate base.
Base Revenues General Rate Cases The GRC is the primary proceeding in which the CPUC determines the amount of base revenue requirements that the Utility is authorized to collect from customers to recover the Utility’s anticipated costs related to its electric distribution, natural gas distribution, and Utility-owned electric generation operations and return on rate base.
Risk Factors. It is also expected that some publicly-owned utilities will build new or duplicate transmission or distribution facilities to serve existing or potential new Utility customers. In some instances, microgrid formation is a key factor in a community’s choice to engage governmental entities.
It is also expected that some publicly-owned utilities will build new or duplicate transmission or distribution facilities to serve existing or potential new Utility customers, bypassing the Utility’s electric infrastructure. In some instances, microgrid formation is a key factor in a community’s choice to engage governmental entities.
New NEM customers, as well as customers interconnecting on the successor to the NEM tariffs, are required to pay an interconnection fee, utilize time of use rates, and are required to pay certain non-bypassable charges to help fund some of the costs of low income, energy efficiency, and other programs that other customers pay.
Like NEM customers, customers interconnecting on the NBT, are required to pay an interconnection fee, utilize time of use rates, and pay certain non-bypassable charges to help fund some of the costs of low income, energy efficiency, and other programs that other customers pay.
The OEIS is also responsible for reviewing and issuing the Utility’s annual safety certification, annually reviewing and approving the Utility’s executive compensation plan, conducting assessments of the Utility’s safety culture, and conducting field inspections of wildfire mitigation activities.
The OEIS is also responsible for reviewing and issuing the Utility’s annual safety certification, annually reviewing and approving the Utility’s executive compensation plan, conducting assessments of the Utility’s safety culture, conducting field inspections of wildfire mitigation activities, and reviewing proposed undergrounding plans under SB 884.
Electricity Distribution The Utility’s electric distribution network consists of approximately 108,000 circuit miles of distribution lines (of which, as of December 31, 2022, approximately 25% are underground and approximately 75% are overhead), 67 transmission switching substations, and 752 distribution substations with a capacity of approximately 36,000 MVA.
The Utility’s electric distribution network consists of approximately 108,000 circuit miles of distribution lines (of which, as of December 31, 2023, approximately 26% are underground and approximately 74% are overhead), 67 transmission switching substations, and 752 distribution substations with a capacity of approximately 36,000 MVA.
The Utility may in the future incur additional costs to procure renewable energy to meet the new renewable energy targets, which the Utility expects will continue to be recoverable through rates as “pass-through” costs.
The Utility may in the future incur additional costs to procure renewable energy to meet the new renewable energy targets, which the Utility expects will continue to be recoverable through rates as “pass-through” costs. The Utility also may be subject to penalties for failure to meet the higher targets.
Due to the seasonal nature of the Utility’s business and rate design, customer electric bills are generally higher during summer months (May to October) because of higher demand, driven by air conditioning loads. Customer bills related to gas service are generally higher during winter months (November to March) because of higher demand due to heating.
Due to the seasonal nature of the Utility’s business and rate design, customer electric bills are generally higher during summer months (May to October) because of higher demand, driven by air conditioning loads.
For risks in connection with increasing competition, see Item 1A. Risk Factors. Competition in the Natural Gas Industry The Utility competes with other natural gas pipeline companies for customers transporting natural gas into the southern California market on the basis of transportation rates, access to competitively priced supplies of natural gas, and the quality and reliability of transportation services.
Competition in the Natural Gas Industry The Utility competes with other natural gas pipeline companies for customers transporting natural gas into the southern California market on the basis of transportation rates, access to competitively priced supplies of natural gas, and the quality and reliability of transportation services.
Under cost-of-service ratemaking, a utility’s earnings depend on the outcomes of its ratemaking proceedings and its ability to manage costs. See “Ratemaking Mechanisms” below and “Regulatory Matters” in Item 7. MD&A for more information on specific CPUC and FERC proceedings.
Under cost-of-service ratemaking, a utility’s earnings depend on the outcomes of its ratemaking proceedings and its ability to manage costs. See “Ratemaking Mechanisms” below and “Regulatory Matters” in Item 7.
(6) Amount is comprised of renewable, nuclear, and large hydroelectric facility resources generated, procured, and sold. Renewable Energy Resources California law established an RPS that requires LSEs, such as the Utility, to gradually increase the amount of renewable energy they deliver to their customers.
(6) Amount is comprised of renewable, nuclear, and large hydroelectric facility resources generated, procured, and sold. 29 Renewable Energy Resources California law established an RPS that requires LSEs, such as the Utility, to gradually increase the amount of renewable energy they deliver to their customers. See “Environmental Regulation - Air Quality and Climate Change” above.
All of these facilities are located in Fresno County, except for Guernsey solar station, which is located in Kings County. The Utility has applied to transfer its non-nuclear generation assets to Pacific Generation and potentially sell a minority interest in Pacific Generation.
All of these facilities are located in Fresno County, except for Guernsey solar station, which is located in Kings County. The Utility has applied to transfer its non-nuclear generation assets to Pacific Generation and potentially sell a minority interest in Pacific Generation. (For more information, see “Application with Pacific Generation for Approval to Transfer Non-Nuclear Generation Assets” in Item 7.
Mitigating and adapting to the impacts of climate change presents opportunities for growth for the Utility’s business and economic opportunity for the communities it serves. 12 The Utility strives to be prepared to continue to deliver safe, clean, affordable, and reliable energy in the face of increasingly severe and extreme climate-driven natural hazards.
Mitigating and adapting to the impacts of climate change presents opportunities for growth for the Utility’s business and economic opportunity for the communities it serves. The Utility is committed to delivering safe, clean, affordable, and reliable energy in the face of increasingly severe and extreme climate-driven natural hazards.
Natural Gas Utility Operations The Utility provides natural gas transportation services to “core” customers (i.e., small commercial and residential customers) and to “non-core” customers (i.e., industrial, large commercial, and natural gas-fired electric generation facilities) that are connected to the Utility’s gas system in its service area.
(3) These amounts represent revenues authorized to be billed. 32 Natural Gas Utility Operations The Utility provides natural gas transportation services to “core” customers (i.e., small commercial and residential customers) and to “non-core” customers (i.e., industrial, large commercial, and natural gas-fired electric generation facilities) that are connected to the Utility’s gas system in its service area.
The Utility’s deliveries were primarily from renewable energy resources that qualify under California’s RPS and other GHG-free resources (i.e., nuclear, and large hydroelectric generation). California’s RPS requirements and SB 100 goal to serve 100% of retail electricity sales with GHG-free resources by 2045 are discussed further below and in the Environmental Regulation section above.
The Utility’s deliveries were primarily from renewable energy resources that qualify under California’s RPS and other GHG-free resources (i.e., nuclear, and large hydroelectric generation). California’s RPS requirements and SB 100 goal is to serve 100% of retail electricity sales with GHG-free resources by 2045.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

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Biggest changeRisks related to financial conditions, including risks related to: • PG&E Corporation’s and the Utility’s substantial indebtedness; • Restrictions in indebtedness documents; • Appeals of the Confirmation Order; • Potential additional dilution to holders of PG&E Corporation common stock; • Any substantial sale of stock by existing stockholders; • Ownership and transfer restrictions associated with PG&E Corporation common stock; • Tax-related risks and uncertainties, including the grantor trust election for the Fire Victim Trust; • The inability of PG&E Corporation to use some or all of its net operating loss carryforwards and other tax attributes to offset future income; • Restrictions on PG&E Corporation’s and the Utility’s ability to issue dividends; • PG&E Corporation’s reliance on dividends, distributions and other payments from the Utility; • Restrictions on shareholders ’ ability to change the direction or management of PG&E Corporation; • The COVID-19 pandemic; 36 • Increased customer rates; and • Inflation.
Biggest changeRisks related to financial conditions, including risks related to: • PG&E Corporation’s and the Utility’s substantial indebtedness; • Restrictions in indebtedness documents; • Potential additional dilution to holders of PG&E Corporation common stock; • Ownership and transfer restrictions associated with PG&E Corporation common stock; • The inability of PG&E Corporation to use some or all of its net operating loss carryforwards and other tax attributes to offset future income; • PG&E Corporation’s reliance on dividends, distributions and other payments from the Utility; • Restrictions on shareholders’ ability to change the direction or management of PG&E Corporation; 36 • Increased customer rates; • T h e Utility ’ s ability to manage its costs effectively; and • Inflation and supply chain issues .
Risks related to environmental factors, including risks related to: • Severe weather conditions, extended drought and climate change and events resulting from these conditions (including wildfires); and • Extensive environmental laws.
Risks related to environmental factors, including risks related to: • Severe weather events , extended drought and climate change and events resulting from these conditions (including wildfires); and • Extensive environmental laws.
Under this structure, NEM customers do not pay their proportionate share of the cost of maintaining and operating the electric transmission and distribution system, including costs associated with funding social equity programs, subject to certain exceptions, while still receiving electricity from the system when their self-generation is inadequate to meet their electricity needs.
Under this structure, NEM and NBT customers do not pay their proportionate share of the cost of maintaining and operating the electric transmission and distribution system, including costs associated with funding social equity programs, subject to certain exceptions, while still receiving electricity from the system when their self-generation is inadequate to meet their electricity needs.
If the CPUC fails to adjust the Utility’s rates to reflect the impact of events or conditions caused by climate change, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected. The Utility’s operations are subject to extensive environmental laws, and such laws could change.
If the CPUC fails to adjust the Utility’s rates to reflect the impact of events or conditions caused by climate change, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected. 44 The Utility’s operations are subject to extensive environmental laws, and such laws could change.
The costs of participating in the Wildfire Fund are expected to exceed $6.7 billion over the anticipated ten-year contribution period for the fund. The timing and amount of any potential charges associated with the Utility’s contributions would also depend on various factors.
The costs of participating in the Wildfire Fund are expected to exceed $6.7 billion over the ten-year contribution period for the fund. The timing and amount of any potential charges associated with the Utility’s contributions would also depend on various factors.
The Utility has been in the past, and may be in the future, required to pay for environmental remediation costs at sites where it is identified as a potentially responsible party under federal and state environmental laws.
The Utility has been in the past, and may be in the future, required to pay for environmental remediation costs at sites where it is or may be identified as a potentially responsible party under federal and state environmental laws.
These unpaid costs are subsidized by customers not participating in NEM. Accordingly, as more electric customers switch to NEM and self-generate energy, the burden on the remaining customers increases, which in turn encourages more self-generation, further increasing rate pressure on existing non-NEM customers. Other long-term trends could also increase costs for gas customers.
These unpaid costs are subsidized by customers not participating in NEM or NBT. Accordingly, as more electric customers switch to the NBT and self-generate energy, the burden on the remaining customers increases, which in turn encourages more self-generation, further increasing rate pressure on existing non-NEM or non-NBT customers. Other long-term trends could also increase costs for gas customers.
For more information on wildfire recovery risk, see “The Wildfire Fund and other provisions of AB 1054 may not effectively mitigate the risk of liability for damages arising from catastrophic wildfires” above and Note 15 of the Notes to the Consolidated Financial Statements in Item 8. 38 The Utility may not effectively implement its wildfire mitigation initiatives.
For more information on wildfire recovery risk, see “The Wildfire Fund and other provisions of AB 1054 may not effectively mitigate the risk of liability for damages arising from catastrophic wildfires” above and Note 14 of the Notes to the Consolidated Financial Statements in Item 8. 38 The Utility may not effectively implement its wildfire mitigation initiatives.
The following discussion of key risk factors should be considered in evaluating an investment in PG&E Corporation and the Utility and should be read in conjunction with Item 7. MD&A and the Consolidated Financial Statements and related notes in Part II, Item 8, “Financial Statements and Supplementary Data” of this 2022 Form 10-K.
The following discussion of key risk factors should be considered in evaluating an investment in PG&E Corporation and the Utility and should be read in conjunction with Item 7. MD&A and the Consolidated Financial Statements and related notes in Part II, Item 8, “Financial Statements and Supplementary Data” of this 2023 Form 10-K.
The CCPA provides for financial penalties in the event of non-compliance and statutory damages in the event of a data security breach. On November 3, 2020, Californians voted to approve Proposition 24, a ballot measure that creates the California Privacy Rights Act (the “CPRA”), which amended and expanded the CCPA.
The CCPA provides for financial penalties in the event of non-compliance and statutory damages in the event of a data security breach. On November 3, 2020, Californians voted to approve Proposition 24, a ballot measure that created the California Privacy Rights Act (the “CPRA”), which amended and expanded the CCPA.
The Utility also has an obligation to decommission its electricity generation facilities, including its nuclear facilities, as well as gas transmission system assets, at the end of their useful lives. See “Asset Retirement Obligations” in Note 3 of the Notes to the Consolidated Financial Statement in Item 8.
The Utility also has an obligation to decommission its electricity generation facilities, including its nuclear facilities, as well as gas transmission system assets, at the end of their useful lives. See “Asset Retirement Obligations” in Note 2 of the Notes to the Consolidated Financial Statement in Item 8.
For more information on the disallowance cap, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8. Furthermore, the Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund.
For more information on the disallowance cap, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8. Furthermore, the Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund.
The Utility’s ability to efficiently construct, maintain, operate, protect, and decommission its facilities, and provide electricity and natural gas services safely and reliably is subject to numerous risks, many of which are beyond the Utility’s control, including those that arise from: • the breakdown or failure of equipment, electric transmission or distribution lines, or natural gas transmission and distribution pipelines or other assets or group of assets, that can cause explosions, fires, public or workforce safety issues, large scale system disruption or other catastrophic events; 39 • an overpressure event occurring on natural gas facilities due to equipment failure, incorrect operating procedures or failure to follow correct operating procedures, or welding or fabrication-related defects, that results in the failure of downstream transmission pipelines or distribution assets and uncontained natural gas flow; • the failure to maintain adequate capacity to meet customer demand on the gas system that results in customer curtailments, controlled or uncontrolled gas outages, gas surges back into homes, serious personal injury or loss of life; • a prolonged statewide electrical black-out that results in damage to the Utility’s equipment or damage to property owned by customers or other third parties; • the failure to fully identify, evaluate, and control workplace hazards that result in serious injury or loss of life for employees, contractors, or the public, environmental damage, or reputational damage; • the release of radioactive materials caused by a nuclear accident, seismic activity, natural disaster, or terrorist act; • the failure of a large dam or other major hydroelectric facility, or the failure of one or more levees that protect land on which the Utility’s assets are built; • the failure to take expeditious or sufficient action to mitigate operating conditions, facilities, or equipment, that the Utility has identified, or reasonably should have identified, as unsafe, which failure then leads to a catastrophic event (such as a wildfire or natural gas explosion); • inadequate emergency preparedness plans and the failure to respond effectively to a catastrophic event that can lead to public or employee harm or extended outages; • operator or other human error; • a motor vehicle or aviation incident involving a Utility vehicle or aircraft, respectively (or one operated on behalf of the Utility) resulting in serious injuries to or fatalities of the workforce or the public, property damage, or other consequences; • an ineffective records management program that results in the failure to construct, operate and maintain a utility system safely and prudently; • construction performed by third parties that damages the Utility’s underground or overhead facilities, including, for example, ground excavations or “dig-ins” that damage the Utility’s underground pipelines, the risk of which may be exacerbated if the Utility does not have an effective contract management system; • the release of hazardous or toxic substances into the air, water, or soil, including, for example, gas leaks from natural gas storage facilities; flaking lead-based paint from the Utility’s facilities, and leaking or spilled insulating fluid from electrical equipment; and • attacks by third parties, including cyber-attacks, acts of terrorism, vandalism, or war.
The Utility’s ability to efficiently construct, maintain, operate, protect, and decommission its facilities, and provide electricity and natural gas services safely and reliably is subject to numerous risks, some of which are beyond the Utility’s control, including those that arise from: • the breakdown, failure of, or supply challenges with equipment, electric transmission or distribution lines, or natural gas transmission and distribution pipelines or other assets or group of assets, that can cause explosions, fires, public or workforce safety issues, large scale system disruption, or other catastrophic events; • an overpressure event occurring on natural gas facilities due to equipment failure, incorrect operating procedures or failure to follow correct operating procedures, or welding or fabrication-related defects, that results in the failure of downstream transmission pipelines or distribution assets and uncontained natural gas flow; 39 • the failure to maintain adequate capacity to meet customer demand on the gas system that results in customer curtailments, controlled or uncontrolled gas outages, gas surges back into homes, serious personal injury or loss of life; • a significant prolonged electrical black-out that results in damage to the Utility’s equipment or losses for customers or other third parties; • the failure to fully identify, evaluate, and control workplace hazards that result in serious injury or loss of life for employees, contractors, or the public, environmental damage, or reputational damage; • the release of radioactive materials caused by a nuclear accident, seismic activity, natural disaster, or terrorist act; • the failure of a large dam or other major hydroelectric facility, or the failure of one or more levees that protect land on which the Utility’s assets are built; • the failure to take expeditious or sufficient action to mitigate operating conditions, facilities, or equipment, that the Utility has identified, or reasonably should have identified, as unsafe, which failure then leads to a catastrophic event (such as a wildfire or natural gas explosion); • inadequate emergency preparedness plans and the failure to respond effectively to a catastrophic event that can lead to public or employee harm or extended outages; • operator or other human error; • a motor vehicle or aviation incident involving a Utility vehicle or aircraft, respectively (or one operated on behalf of the Utility) resulting in serious injuries to or fatalities of the workforce or the public, property damage, or other consequences; • an ineffective records management program that results in the failure to construct, operate and maintain a utility system safely and prudently; • construction performed by third parties that damages the Utility’s underground or overhead facilities, including, for example, ground excavations or “dig-ins” that damage the Utility’s underground pipelines, the risk of which may be exacerbated if the Utility does not have an effective contract management system; • the release of hazardous or toxic substances into the air, water, or soil, including, for example, gas leaks from natural gas storage facilities; flaking lead-based paint from the Utility’s facilities; leaking or spilled insulating fluid from electrical equipment; and release of contaminants caused by the failure of battery energy storage systems; and • attacks by third parties, including cyber-attacks, acts of terrorism, vandalism, or war.
In addition, wildfires have had and could continue to have (as a result of any future wildfires) adverse consequences on the Utility’s proceedings with the CPUC (including the Safety Culture OII) and the FERC, and future regulatory proceedings, including future applications with the OEIS for the safety certification required by AB 1054.
In addition, wildfires have had and could continue to have (as a result of any future wildfires) adverse consequences on the Utility’s proceedings with the CPUC and the FERC, and future regulatory proceedings, including future applications with the OEIS for the safety certification required by AB 1054.
Reducing natural gas use could lead to a reduction in the gas customer base and a diminished need for gas infrastructure and, as a result, could lead to certain gas assets no longer being “used and useful,” potentially causing substantial investment value of gas assets to be stranded (under CPUC precedent, when an asset no longer meets the standard of “used and useful,” the asset is removed from rate base, which results in a reduction in associated rate recovery).
Reducing natural gas use reduces the gas customer base and could diminish the need for gas infrastructure and, as a result, could lead to certain gas assets no longer being “used and useful,” potentially causing substantial investment value of gas assets to be stranded (under CPUC precedent, when an asset no longer meets the standard of “used and useful,” the asset is removed from rate base, which results in a reduction in associated rate recovery).
For example, the Utility may not be able to effectively implement its WMPs if it experiences unanticipated difficulties relative to sourcing, engaging, training, overseeing, and retaining contract workers it needs to fulfill its mitigation obligations under the WMPs.
For example, the Utility may not be able to effectively implement its WMPs if it experiences unanticipated difficulties relative to sourcing, engaging, training, overseeing, or retaining contract workers it needs to fulfill its mitigation obligations under the WMPs.
The Utility has experienced shortages in certain materials, longer lead times and delivery delays as a result of domestic and international raw material and labor shortages. If these disruptions to the supply chain persist or worsen, the Utility may be delayed or prevented from completing planned maintenance and capital projects work.
Additionally, the Utility has experienced shortages in certain items, longer lead times, and delivery delays as a result of domestic and international raw material and labor shortages. If these disruptions to the supply chain persist or worsen, the Utility may be delayed or prevented from completing planned maintenance and capital projects work.
For more information about the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8.
For more information about the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8.
However, while natural gas demand is projected to decline over time, the costs of operating a safe and reliable gas delivery system in California have been increasing, among other things, to cover the cost of long-term pipeline safety enhancements.
However, even as natural gas demand is projected to decline over time, the costs of operating a safe and reliable gas delivery system in California have been increasing, among other things, to cover the cost of long-term pipeline safety enhancements.
For instance, the Utility may be unable to procure an adequate supply of nuclear fuel. For more information, see “Extension of Diablo Canyon Operations” under “Legislative and Regulatory Initiatives” in Item 7. MD&A. The Utility has incurred, and may continue to incur, substantial costs to comply with NRC regulations and orders. See “Regulatory Environment” in Item 1. Business above.
For instance, the Utility may be unable to procure an adequate supply of nuclear fuel. For more information, see “Extension of Diablo Canyon Operations” under “Other Regulatory Proceedings” in Item 7. MD&A. The Utility has incurred, and may continue to incur, substantial costs to comply with NRC regulations and orders. See “Regulatory Environment” in Item 1. Business above.
As a capital-intensive company, the Utility relies on access to the capital markets. If the Utility were unable to access the capital markets or the cost of financing were to substantially increase, its financial condition, results of operations, liquidity, and cash flows could be materially affected.
As a capital-intensive company, the Utility relies on access to the capital markets, particularly investment grade capital markets. If the Utility were unable to access the capital markets or the cost of financing were to substantially increase, its financial condition, results of operations, liquidity, and cash flows could be materially affected.
If the Internal Revenue Service successfully asserts that PG&E Corporation did undergo, or PG&E Corporation otherwise does undergo, an ownership change, the limitation on its net operating loss carryforwards and other tax attributes under Section 382 of the IRC could be material to PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
If the IRS successfully asserts that PG&E Corporation did undergo, or PG&E Corporation otherwise does undergo, an ownership change, the limitation on its net operating loss carryforwards and other tax attributes under Section 382 of the IRC could be material to PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
See “The Wildfire Fund and other provisions of AB 1054 may not effectively mitigate the risk of liability for damages arising from catastrophic wildfires.” above. Privacy In June 2018, the State of California enacted the CCPA, which went into effect on January 1, 2020, with a 12-month look-back period requiring compliance by January 1, 2019.
See “The Wildfire Fund and other provisions of AB 1054 may not effectively mitigate the risk of liability for damages arising from catastrophic wildfires.” above. 45 Privacy In June 2018, the State of California enacted the California Consumer Privacy Act of 2018 (the “CCPA”), which went into effect on January 1, 2020, with a 12-month look-back period requiring compliance by January 1, 2019.
The Utility may incur a material charge if it ceases operations at Diablo Canyon’s two nuclear generation units before their respective current licenses expire in 2024 and 2025. As of December 31, 2022, the Utility’s unrecovered investment in Diablo Canyon was $840 million.
The Utility may incur a material charge if it ceases operations at Diablo Canyon’s two nuclear generation units before their respective current licenses expire in 2024 and 2025. As of December 31, 2023, the Utility’s unrecovered investment in Diablo Canyon was $595 million.
If municipalization proceedings are permitted to move forward and are successful, the Utility would be entitled to receive the fair market value of the assets that are subject to the takeover effort, but the valuation issues in any municipalization proceeding would be highly contentious and could result in the Utility receiving less than what it believes is just compensation for the applicable assets.
If municipalization proceedings are permitted to move forward and are successful, the Utility would be entitled to receive the fair market value of the assets that are subject to the takeover effort, as well as associated severance damages, but valuation issues in any municipalization proceeding would be highly contentious and could result in the Utility receiving less than what it believes is just compensation for the applicable assets.
PG&E Corporation and the Utility could be materially affected by legislative and regulatory developments. The Utility and its operations are subject to extensive federal, state, and local laws, regulations, and orders. The Utility incurs significant capital, operating, and other costs associated with compliance with these rules.
PG&E Corporation and the Utility could incur significant costs to comply with laws and regulations and be adversely affected by legislative and regulatory developments. The Utility and its operations are subject to extensive federal, state, and local laws, regulations, and orders. The Utility incurs significant capital, operating, and other costs associated with compliance with these rules.
Risks related to wildfires, including risks related to: • The extent to which the Wildfire Fund and revised recoverability standard under AB 1054 effectively mitigate the risk of liability for damages arising from catastrophic wildfires; • The 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, the 2022 Mosquito fire , or future wildfires; • Recovery of excess costs in connection with wildfires; and 35 • Implementation of wildfire mitigation initiatives.
These risks are discussed more fully below. 35 Risks related to wildfires, including risks related to: • The extent to which the Wildfire Fund and revised recoverability standard under AB 1054 effectively mitigate the risk of liability for damages arising from catastrophic wildfires; • The 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, the 2022 Mosquito fire, or future wildfires; • Recovery of excess costs in connection with wildfires; and • Implementation of wildfire mitigation initiatives.
Risks related to enforcement matters, investigations, and regulatory proceedings, including risks related to: • The Enhanced Oversight and Enforcement Process; • Legislative and regulatory developments; • Outcomes of enforcement proceedings in connection with extensive regulations to which the Utility is subject; and • Outcomes of regulatory and ratemaking proceedings and the Utility’s ability to manage its costs.
Risks related to enforcement matters, investigations, and regulatory proceedings, including risks related to: • The Enhanced Oversight and Enforcement Process; • Legislative and regulatory developments; • Outcomes of enforcement proceedings in connection with extensive regulations to which the Utility is subject; • Outcomes of regulatory and ratemaking proceedings and the Utility’s ability to manage its cost s; and • Municipalization .
Some of these nuclear opposition groups regularly file petitions at the NRC and in other forums challenging the actions of the NRC and urging governmental entities to adopt laws or policies in opposition to nuclear power. Although an action in opposition may ultimately fail, regulatory proceedings may take longer to conclude and be more costly to complete.
Some of these nuclear opposition groups regularly file petitions at the NRC and in other forums challenging the actions of the NRC and urging governmental entities to adopt laws or policies in opposition to nuclear power. Even if an action in opposition ultimately fails, regulatory proceedings may take longer to conclude and be more costly to complete.
See “Environmental Regulation” in Item 1. and Note 16 of the Notes to the Consolidated Financial Statements in Item 8.
See “Environmental Regulation” in Item 1 and Note 15 of the Notes to the Consolidated Financial Statements in Item 8.
Any failure or decrease in the functionality of the Utility’s operational networks could cause harm to the public or employees, significantly disrupt operations, negatively impact the Utility’s ability to safely generate, transport, deliver and store energy and gas or otherwise operate in the most safe and efficient manner or at all, and damage the Utility’s assets or operations or those of third parties. 41 The Utility also relies on complex information technology systems that allow it to create, collect, use, disclose, store and otherwise process sensitive information, including the Utility’s financial information, customer energy usage and billing information, and personal information regarding customers, employees and their dependents, contractors, and other individuals.
Any failure, interruption, or decrease in the functionality of the Utility’s operational networks could cause harm to the public or employees, significantly disrupt operations, negatively impact the Utility’s ability to safely generate, transport, deliver and store energy and gas or otherwise operate in a safe and efficient manner or at all, and damage the Utility’s assets or operations or those of third parties. 41 The Utility also relies on complex information technology systems that allow it to create, collect, use, disclose, store and otherwise process sensitive information, including the Utility’s financial information, customer energy usage and billing information, and personal information regarding customers, employees and their dependents, contractors, and other individuals, and portions of such sensitive information may be required to be encrypted by the Utility.
In addition, PG&E Corporation had $500 million of additional borrowing capacity under the Corporation Revolving Credit Agreement, and the Utility had $1.5 billion of additional borrowing capacity under the Utility Revolving Credit Agreement. In addition, the Utility had outstanding preferred stock with an aggregate liquidation preference of $252 million.
In addition, PG&E Corporation had $500 million of additional borrowing capacity under the Corporation Revolving Credit Agreement, and the Utility had $2.0 billion of additional borrowing capacity under the Utility Revolving Credit Agreement. In addition, the Utility had outstanding preferred stock with an aggregate liquidation preference of $252 million.
Any of these factors, in whole or in part, could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Risk Factors Summary The following is a summary of the principal risks that could adversely affect our business, operations, and financial results. These risks are discussed more fully below.
Any of these factors, in whole or in part, could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Risk Factors Summary The following is a summary of the principal risks that could adversely affect our business, operations, and financial results.
Such events could subject the Utility to significant expenses, claims by customers or third parties, government inquiries, penalties for violation of applicable privacy laws, investigations, and regulatory actions that could result in material fines and penalties, loss of customers and harm to PG&E Corporation’s and the Utility’s reputation, any of which could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
Such events could subject the Utility to significant expenses, claims by customers or third parties, government inquiries, penalties for violation of applicable privacy laws, investigations, lawsuits, and regulatory actions and could result in material fines, penalties, loss of customers, and harm to PG&E Corporation’s and the Utility’s reputation, any of which could have a material effect on PG&E Corporation’s and the Utility’s business strategy, financial condition, or results of operations.
Although PG&E Corporation and the Utility invest in risk management and information security measures, the personal information that they collect, as well as other commercially-sensitive data that they possess, could become compromised because of certain events, including a cyber incident, the insufficiency or failure of such measures, human error, the misappropriation of data, or the occurrence of any of the foregoing at any third party with which PG&E Corporation or the Utility has shared information.
PG&E Corporation’s and the Utility’s risk management and information security measures may be ineffective, and the personal information that they collect, as well as other commercially-sensitive data that they possess, could become compromised because of certain events, including a cyber incident, the insufficiency or failure of such measures, human error, the misappropriation of data, or the occurrence of any of the foregoing at any third party with which PG&E Corporation or the Utility has shared information.
Furthermore, since a significant percentage of the Utility’s assets are used to secure its debt, this reduces the amount of collateral available for future secured debt or credit support and reduces its flexibility in operating these secured assets.
Furthermore, since a significant percentage of the Utility’s assets are used to secure its debt, this reduces the amount of collateral available for future secured debt or credit support and reduces its flexibility in operating these secured assets or using them for other financing transactions.
Increasing levels of self-generation of electricity by customers (primarily solar installations) and customer enrollment in NEM, which allows self-generating customers to receive bill credits for power exported to the grid at the full retail rate, shifts costs to other customers.
Increasing levels of self-generation of electricity by customers (primarily solar installations) and customer enrollment in NEM and NBT, which allows self-generating customers to receive bill credits for power exported to the grid, shifts costs to other customers.
Risks related to operations and information technology, including risks related to: • The hazardous nature of the Utility’s electricity and natural gas operations; • Changes in the electric power and gas industries; • A cyber incident, cyber security breach, severe natural event or physical attack; • The operation and decommissioning of the Utility’s nuclear generation facilities; and • Attracting and retaining specialty personnel.
Risks related to operations and information technology, including risks related to: • The hazardous nature of the Utility’s electricity and natural gas operations; • Changes in the electric power and nat ural gas industries; • A cyber incident, cybersecurity breach , or physical attack; • The operation and decommissioning of the Utility’s nuclear generation facilities; and • Attracting and retaining specialty personnel.
However, whether PG&E Corporation underwent or will undergo an ownership change as a result of the transactions in PG&E Corporation’s equity that occurred pursuant to the Plan depends on several factors outside PG&E Corporation’s control and the application of certain laws that are uncertain in several respects.
However, whether PG&E Corporation underwent an ownership change as a result of the transactions in PG&E Corporation’s equity that occurred pursuant to the Plan or in combination with other changes in the ownership of PG&E Corporation’s equity depends on several factors outside PG&E Corporation’s control and the application of certain laws that are uncertain in several respects.
There can be no assurance that the Utility will be allowed to recover costs in excess of insurance or amounts potentially available under the Wildfire Fund under AB 1054 in the future either through FERC TO rates or as costs recorded to the WEMA, even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation.
The Utility may not be allowed to recover costs in excess of insurance or amounts potentially available under the Wildfire Fund under AB 1054 in the future either through FERC TO rates or as costs recorded to the WEMA, even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation.
PG&E Corporation has incurred and may also continue to incur, in connection with the Plan, significant net operating loss carryforwards and other tax attributes, the amount and availability of which are subject to certain qualifications, limitations and uncertainties.
PG&E Corporation has incurred and may also incur in the future significant net operating loss carryforwards and other tax attributes, the amount and availability of which are subject to certain qualifications, limitations and uncertainties.
There can be no assurance that the Utility will be successful in retaining highly skilled personnel under its employee programs. 42 The Utility is pursuing the extension of operations at Diablo Canyon through no later than 2030. If Diablo Canyon enters extended operations, the Utility will face operational challenges resulting from a shortened planning period.
The Utility may not be successful in retaining highly skilled personnel under its employee programs. The Utility is pursuing the extension of operations at Diablo Canyon through no later than 2030. If Diablo Canyon enters extended operations, the Utility will face operational challenges resulting from a shortened planning period.
The Utility often relies on third-party vendors to host, maintain, modify, and update its systems, and to provide other services to the Utility or the Utility’s customers.
The Utility often relies on third-party vendors to host, maintain, modify, and update its systems (including providing security updates), and to provide other services to the Utility or the Utility’s customers.
Reduced energy demand or significantly slowed growth in demand due to customer migration to other energy providers, adoption of energy efficient technology, conservation, increasing levels of distributed generation and self-generation, unless substantially offset through regulatory cost allocations, could increase the energy rates for other customers. If rates were to rise too rapidly, customer usage could decline.
Reduced energy demand or significantly slowed growth in demand due to customer migration to other energy providers, adoption of energy efficient technology, conservation, increasing levels of distributed generation and self-generation, unless substantially offset through regulatory cost allocations, could increase the energy rates for other customers.
The Utility could be subject to additional regulatory or governmental enforcement action in the future with respect to compliance with federal, state, or local laws, regulations or orders that could result in additional fines, penalties or customer refunds, including those regarding renewable energy and RA requirements; customer billing; customer service; affiliate transactions; vegetation management; design, construction, operating and maintenance practices; safety and inspection practices; compliance with CPUC GOs or other applicable CPUC decisions or regulations; whether the Utility is able to achieve the targets in its WMPs; federal electric reliability standards; and environmental compliance.
In addition, the OEIS has authority to approve and oversee compliance with the WMP and may determine that the Utility has failed to substantially comply with its WMP. 46 The Utility could be subject to additional regulatory or governmental enforcement action in the future with respect to compliance with federal, state, or local laws, regulations or orders that could result in additional fines, penalties or customer refunds, including those regarding renewable energy and RA requirements; customer billing; customer service; affiliate transactions; vegetation management; design, construction, operating and maintenance practices; safety and inspection practices; compliance with CPUC GOs or other applicable CPUC decisions or regulations; whether the Utility is able to achieve the targets in its WMPs; federal electric reliability standards; and environmental compliance.
PG&E Corporation and the Utility could be the subject of additional investigations, lawsuits, or enforcement actions in connection with the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, the 2022 Mosquito fire, or other wildfires.
PG&E Corporation and the Utility have been the subject of investigations, regulatory enforcement actions, or criminal proceedings in connection with wildfires and could be the subject of additional investigations, regulatory enforcement actions, or criminal proceedings in connection with the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, the 2022 Mosquito fire, or other wildfires.
These and other provisions in the Amended Articles, the Amended Bylaws, and California law could make it more difficult for shareholders or potential acquirers to obtain control of the Board of Directors or initiate actions that are opposed by the then-current Board of Directors, including delaying or impeding merger, tender offer, or proxy contest involving PG&E Corporation.
MD&A)), subject to certain exceptions as may be determined by the Board of Directors of PG&E Corporation. 51 These and other provisions in the Amended Articles, the Amended Bylaws, and California law could make it more difficult for shareholders or potential acquirers to obtain control of the Board of Directors or initiate actions that are opposed by the then-current Board of Directors, including delaying or impeding merger, tender offer, or proxy contest involving PG&E Corporation.
For more information, see “The Utility’s operational networks and information technology systems could be impacted by a cyber incident, cyber security breach, severe natural event or physical attack” below.
For more information, see “The Utility’s operational networks and information technology systems could be impacted by a cyber incident, cybersecurity breach, or physical attack” below.
The Utility and its third-party vendors have been subject to, and will likely continue to be subject to, breaches and attempts to gain unauthorized access to the Utility’s information technology systems or confidential data (including information about customers and employees), or to disrupt the Utility’s operations.
PG&E Corporation, the Utility and their third-party vendors have been subject to, and will likely continue to be subject to, threats, breaches and attempts to gain unauthorized access to the Utility’s information technology systems or confidential or sensitive data (including information about customers and employees), or to disrupt the Utility’s operations.
The Utility’s electricity and natural gas systems rely on a complex, interconnected network of generation, transmission, distribution, control, and communication technologies, which can be damaged by natural events-such as severe weather or seismic events-and by malicious events, such as cyber and physical attacks.
The Utility’s electricity and natural gas systems rely on a complex, interconnected network of generation, transmission, distribution, control, and communication technologies, which can be damaged by natural events-such as severe weather or seismic events and by malicious events, such as physical and cyber attacks. Nationally, there has been an increase in physical attacks on substations.
For more information on factors that could cause the Utility’s costs to increase, see “The Utility’s ratemaking and cost recovery proceedings may not authorize sufficient revenues, or the Utility’s actual costs could exceed its authorized or forecasted costs due to various factors, including if the Utility is not able to manage its costs effectively” above.
For more information on factors that could cause the Utility’s costs to increase, see “The Utility’s ratemaking and cost recovery proceedings may not authorize sufficient revenues, or the Utility’s actual costs could exceed its authorized or forecasted costs due to various factors” above.
Participation in the Wildfire Fund is expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, and there can be no assurance that the benefits of participating in the Wildfire Fund ultimately outweigh these substantial costs.
Participation in the Wildfire Fund is expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, and the benefits of participating in the Wildfire Fund may not ultimately outweigh these substantial costs.
The Utility’s operational networks and information technology systems could be impacted by a cyber incident, cyber security breach, severe natural event, or physical attack.
The Utility’s operational networks and information technology systems could be impacted by a cyber incident, cybersecurity breach, or physical attack.
While San Francisco would still need to, among other things, initiate and prevail in an eminent domain action in state court to acquire the Utility’s assets, there is no guarantee that the Utility would be successful in defending against such an action or related regulatory proceeding.
San Francisco would still need to, among other things, initiate and prevail in an eminent domain action in state court to acquire the Utility’s assets, but the Utility may not be successful in defending against such an action or related regulatory proceeding.
Under California law (including Penal Code section 1202.4), if the Utility were convicted of any of the charges, the sentencing court must order the Utility to “make restitution to the victim or victims in an amount established by court order” that is “sufficient to fully reimburse the victim or victims for every determined economic loss incurred as the result of” the Utility’s underlying conduct, in addition to interest and the victim’s or victims’ attorneys’ fees.
For more information, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8. 37 Under California law (including Penal Code section 1202.4), if the Utility were convicted of any charges in connection with a wildfire, the sentencing court must order the Utility to “make restitution to the victim or victims in an amount established by court order” that is “sufficient to fully reimburse the victim or victims for every determined economic loss incurred as the result of” the Utility’s underlying conduct, in addition to interest and the victim’s or victims’ attorneys’ fees.
The Utility maintains cyber liability insurance that covers certain damages caused by cyber incidents. However, there is no assurance that adequate insurance will continue to be available at rates the Utility believes are reasonable or that the costs of responding to and recovering from a cyber incident will be covered by insurance or recoverable through rates.
The Utility maintains cyber liability insurance that covers certain losses and damages caused by cyber incidents, but adequate insurance may not continue to be available at rates the Utility believes are reasonable, or the costs of responding to and recovering from a cyber incident may not be covered by insurance or recoverable through rates.
These developments will require sustained investments in grid modernization, renewable integration projects, energy efficiency programs, energy storage options, electric vehicle infrastructure and state infrastructure modernization (e.g., rail and water projects).
In addition, enabling California’s clean energy transition will require sustained investments in grid modernization, renewable energy integration projects, energy efficiency programs, energy storage options, electric vehicle infrastructure, and state infrastructure modernization (e.g., rail and water projects).
The Utility’s ratemaking and cost recovery proceedings may not authorize sufficient revenues, or the Utility’s actual costs could exceed its authorized or forecasted costs due to various factors, including if the Utility is not able to manage its costs effectively.
The Utility’s ratemaking and cost recovery proceedings may not authorize sufficient revenues, or the Utility’s actual costs could exceed its authorized or forecasted costs due to various factors.
Increases in inflation raises costs for labor, materials and services, and PG&E Corporation and the Utility may be unable to secure these resources on economically acceptable terms or offset such costs with increased revenues, operating efficiencies, or cost savings, which may adversely impact PG&E Corporation’s and the Utility’s financial conditions, results of operations, liquidity, and cash flows.
PG&E Corporation and the Utility may be unable to secure these resources on economically acceptable terms or offset such costs with increased revenues, operating efficiencies, or cost savings, which may adversely affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
As of December 31, 2022, PG&E Corporation had approximately $4.68 billion of outstanding indebtedness (such indebtedness consisting of PG&E Corporation’s $1.0 billion aggregate principal amount of senior secured notes due 2028, $1.0 billion aggregate principal amount of senior secured notes due 2030, and borrowings under the $2.75 billion secured term loan agreement entered into in June 2020), and the Utility had approximately $45.6 billion of outstanding indebtedness.
As of December 31, 2023, PG&E Corporation had approximately $4.65 billion of outstanding indebtedness (such indebtedness consisting of PG&E Corporation’s $2.15 billion aggregate principal amount of convertible senior secured notes due 2027, $1.0 billion aggregate principal amount of senior secured notes due 2028, $1.0 billion aggregate principal amount of senior secured notes due 2030, and $500 million of borrowings under the secured term loan agreement entered into in June 2020), and the Utility had approximately $48.0 billion of outstanding indebtedness.
Inability by the Utility to recover through rates its investments into the natural gas system while still ensuring gas system safety and reliability could materially affect the Utility’s financial condition, results of operations, liquidity, and cash flows.
If the Utility is unable to recover through rates its investments into the natural gas system while still ensuring gas system safety and reliability, its financial condition, results of operations, liquidity, and cash flows could be materially affected.
As of December 31, 2022, PG&E Corporation had net operating loss carryforwards for PG&E Corporation’s consolidated group for U.S. federal and California income tax purposes of approximately $26.6 billion and $25.2 billion, respectively, and PG&E Corporation incurred and may also continue to incur, in connection with the Plan, significant net operating loss carryforwards and other tax attributes.
As of December 31, 2023, PG&E Corporation had net operating loss carryforwards for PG&E Corporation’s consolidated group for U.S. federal and California income tax purposes of approximately $32.9 billion and $32.6 billion, respectively, and PG&E Corporation incurred and may also continue to incur significant net operating loss carryforwards and other tax attributes.
See Note 2 of the Notes to the Consolidated Financial Statements in Item 8. 48 PG&E Corporation may be required to issue shares with respect to HoldCo Rescission or Damage Claims, which would result in dilution to holders of PG&E Corporation common stock, or pay a material amount of cash with respect to allowed Subordinated Debt Claims.
PG&E Corporation may be required to issue shares with respect to HoldCo Rescission or Damage Claims, which would result in dilution to holders of PG&E Corporation common stock, or pay a material amount of cash with respect to allowed Subordinated Debt Claims.
This relatively high level of debt and related security could have other important consequences for PG&E Corporation and the Utility, including: • limiting their ability or increasing the costs to refinance their indebtedness; 47 • limiting their ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, execution of their business strategy or other purposes; • limiting their ability to use operating cash flow in other areas of their business; • increasing their vulnerability to general adverse economic and industry conditions, including increases in interest rates, particularly given their substantial indebtedness that bears interest at variable rates, as well as to catastrophic events; and • limiting their ability to capitalize on business opportunities.
This relatively high level of debt and related security could have other important consequences for PG&E Corporation and the Utility, including: • limiting their ability or increasing the costs to refinance their indebtedness; • limiting their ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, execution of their business strategy or other purposes; • limiting their ability to use operating cash flow in other areas of their business; • increasing their vulnerability to general adverse economic and industry conditions, including increases in interest rates, particularly given their substantial indebtedness that bears interest at variable rates, as well as to catastrophic events; and • limiting their ability to capitalize on business opportunities. 48 Under the terms of the agreements and indentures governing their respective indebtedness, PG&E Corporation and the Utility are permitted to incur additional indebtedness, some of which could be secured (subject to compliance with certain tests) and which could further accentuate these risks.
While the Utility continues to dispute the applicability of inverse condemnation to the Utility, there can be no assurance that the Utility will be successful in challenging the applicability of inverse condemnation in the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, the 2022 Mosquito fire, or other litigation against PG&E Corporation or the Utility.
The Utility continues to dispute the applicability of inverse condemnation to the Utility, but the Utility may not be successful in challenging the applicability of inverse condemnation in the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, the 2022 Mosquito fire, or other litigation against PG&E Corporation or the Utility.
The Utility’s costs to remediate groundwater contamination near the Hinkley natural gas compressor site and to abate the effects of the contamination, changes in estimated costs, and the extent to which actual remediation costs differ from recorded liabilities have had, and may continue to have, a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. 44 Risks Related to Other Enforcement Matters, Investigations, and Regulatory Proceedings PG&E Corporation and the Utility are subject to the Enhanced Oversight and Enforcement Process.
The Utility’s costs to remediate groundwater contamination near the Hinkley natural gas compressor site and to abate the effects of the contamination, changes in estimated costs, and the extent to which actual remediation costs differ from recorded liabilities have had, and may continue to have, a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.
See “Trends in Market Demand and Competitive Conditions in the Electricity Industry” in Item 1. Jurisdictions may attempt to acquire the Utility’s assets through eminent domain. Jurisdictions may attempt to acquire the Utility’s assets through eminent domain (“municipalization”).
See “Trends in Market Demand and Competitive Conditions in the Electricity Industry” in Item 1. 47 Jurisdictions may attempt to acquire the Utility’s assets through eminent domain, and third parties may attempt to acquire the Utility’s customers by bypassing the Utility’s electric infrastructure system. Jurisdictions may attempt to acquire the Utility’s assets through eminent domain (“municipalization”).
Although PG&E Corporation and the Utility have recorded liabilities for probable losses in connection with these fires, these liability estimates correspond to the lower end of the range of reasonably estimable losses, do not include several categories of potential damages that are not reasonably estimable, and are subject to change based on new information.
PG&E Corporation’s and the Utility’s recorded liabilities for probable losses in connection with these fires correspond to the lower end of the range of reasonably estimable losses unless there is a better estimate, do not include several categories of potential damages that are not reasonably estimable, and are subject to change based on new information.
The Utility’s level of authorized capital investment could decline as well, leading to a slower growth in rate base and earnings. As a result, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected. Inflation may negatively impact PG&E Corporation’s and the Utility’s financial conditions, results of operations, liquidity, and cash flows.
The Utility’s level of authorized capital investment could decline as well, leading to fewer new business interconnections and a slower growth in rate base and earnings. As a result, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected. Inflation and supply chain issues may adversely affect PG&E Corporation and the Utility.
Assets that are targeted for municipalization generally are located in geographic areas that have a lower cost of service relative to billed revenues, so municipalization could negatively impact the affordability of the Utility’s service for remaining Utility customers served outside of those geographic areas.
Utility assets that are targeted for municipalization, as well as existing or potential future Utility customers targeted for electric services by third parties that bypass the Utility’s facilities, generally are located in geographic areas that have a lower cost of service relative to billed revenues, so municipalization (or bypass) could negatively impact the affordability of the Utility’s service for remaining Utility customers served outside of those geographic areas.
PG&E Corporation and the Utility have observed that prices for equipment, materials, supplies, employee labor, contractor services, and variable-rate debt have increased. Long-term inflationary pressures may result in such prices continuing to increase more quickly than expected.
PG&E Corporation and the Utility have observed that prices for equipment, materials, supplies, employee labor, contractor services, and variable-rate debt have increased and may continue to increase more quickly than expected as a result of inflation.
As further described in “Satisfaction of HoldCo Rescission or Damage Claims and Subordinated Debt Claims” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8, PG&E Corporation may be required to issue shares of its common stock in satisfaction of allowed HoldCo Rescission or Damage Claims.
As further described in “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8, PG&E Corporation may be required to issue shares of its common stock in satisfaction of allowed HoldCo Rescission or Damage Claims.
The extent of damages for a wildfire is primarily determined by environmental conditions (including weather and vegetation conditions), third-party suppression efforts, and the location of the wildfire.
Once an ignition has occurred, the Utility is unable to control the extent of damages. The extent of damages for a wildfire is primarily determined by environmental conditions (including weather and vegetation conditions), third-party suppression efforts, and the location of the wildfire.
Natural gas suppliers are subject to compliance with CARB’s cap-and-trade program, and natural gas end-use customers have an increasing exposure to carbon costs under the program through 2030 (when the full cost will be reflected in customer bills). CARB may also require aggressive energy efficiency programs to reduce natural gas end use.
Natural gas suppliers are subject to compliance with CARB’s cap-and-trade program, and natural gas end-use customers have an increasing exposure to carbon costs under the program through 2030 (when the full cost will be reflected in customer bills). Increased renewable portfolio standards in the electric sector could also reduce electric generation gas load.
Approximately 25,000 circuit miles of the Utility’s nearly 80,000 distribution overhead circuit miles and approximately 5,500 miles of the nearly 18,000 transmission overhead circuit miles are in such HFTDs, significantly more in total than other California IOUs. 43 Severe weather events and other natural disasters, including wildfires and other fires, storms, tornadoes, floods, extreme heat events, drought, earthquakes, lightning, tsunamis, rising sea levels, pandemics, solar events, electromagnetic events, wind events or other weather-related conditions, climate change, or natural disasters, could result in severe business disruptions, prolonged power outages, property damage, injuries and loss of life, significant decreases in revenues and earnings, and significant additional costs to PG&E Corporation and the Utility.
Severe weather events and other natural disasters, including wildfires and other fires, storms, tornadoes, floods, extreme heat events, drought, earthquakes, lightning, tsunamis, rising sea levels, pandemics, solar events, electromagnetic events, wind events or other weather-related conditions, climate change, or natural disasters, could result in severe business or operational disruptions, prolonged power outages, property damage, injuries and loss of life, significant decreases in revenues and earnings, and significant additional costs to PG&E Corporation and the Utility.
Any acquisition of PG&E Corporation capital stock that results in a shareholder being in violation of these restrictions may not be valid. 49 Subject to certain exceptions, the Ownership Restrictions restrict (i) any person or entity (including certain groups of persons) from directly or indirectly acquiring or accumulating 4.75% or more of the outstanding Equity Securities and (ii) the ability of any person or entity (including certain groups of persons) already owning, directly or indirectly, 4.75% or more of the Equity Securities to increase their proportionate interest in the Equity Securities.
Subject to certain exceptions, the Ownership Restrictions restrict (i) any person or entity (including certain groups of persons) from directly or indirectly acquiring or accumulating 4.75% or more of the outstanding Equity Securities and (ii) the ability of any person or entity (including certain groups of persons) already owning, directly or indirectly, 4.75% or more of the Equity Securities to increase their proportionate interest in the Equity Securities.
The Utility is subject to extensive regulations, including federal, state, and local energy, environmental and other laws and regulations, and the risk of enforcement proceedings in connection with compliance with such regulations.
The Utility is subject to extensive regulations, including federal, state, and local energy, environmental and other laws and regulations, and the risk of enforcement proceedings in connection with compliance with such regulations. The Utility could incur material charges, including fines and other penalties, in connection with matters that the CPUC’s SED may investigate.
Environmental remediation costs could increase in the future as a result of new legislation, the current trend toward more stringent standards, or stricter and more expansive application of existing environmental regulations.
For more information, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8. Environmental remediation costs could increase in the future as a result of new legislation or regulation, the current trend toward more stringent standards, or stricter and more expansive application of existing environmental regulations.
This risk may be attributable to, and exacerbated by, a variety of factors, including climate (in particular, extended periods of seasonal dryness coupled with periods of high wind velocities and other storms), infrastructure, and vegetation conditions.
This risk may be attributable to, and exacerbated by, a variety of factors, including climate (in particular, extended periods of seasonal dryness coupled with periods of high wind velocities and other storms), infrastructure, and vegetation conditions. The Utility’s significant infrastructure investment, vegetation management, and de-energization strategies do not eliminate wildfire risk and may not prevent future wildfires.
Because PG&E Corporation and the Utility have elected to treat the Fire Victim Trust as a grantor trust, the application of the Ownership Restrictions, as defined in PG&E Corporation’s Amended Articles of Incorporation, will be determined on the basis of a number of shares outstanding that could differ materially from the number of shares reported as outstanding on the cover page of its periodic reports under the Exchange Act.
Additionally, the application of the Ownership Restrictions, as defined in PG&E Corporation’s Amended Articles of Incorporation, will be determined on the basis of a number of shares outstanding that differs materially from the number of shares reported as outstanding on the cover page of its periodic reports under the Exchange Act because it excludes shares owned by the Utility.

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Item 2. Properties

Properties — owned and leased real estate

4 edited+2 added−2 removed3 unchanged
Biggest changeOn October 23, 2020, the Utility entered into an office lease agreement with BA2 300 Lakeside LLC for approximately 910,000 rentable square feet of space within the Lakeside Building to serve as the Utility’s principal administrative headquarters.
Biggest changeThe Leaseback Agreement commenced on September 17, 2021, and the lease term was extended through June 30, 2024. On October 23, 2020, the Utility entered into an office lease agreement with BA2 300 Lakeside LLC for approximately 910,000 rentable square feet of space within the Lakeside Building to serve as the Utility’s principal administrative headquarters.
In 2002, the Utility agreed to implement its Land Conservation Commitment (“LCC”) to permanently preserve the six “beneficial public values” on all the watershed lands through conservation easements or equivalent protections, as well as to make approximately 40,000 acres of the watershed lands available for donation to qualified organizations.
In 2002, the Utility agreed to implement its LCC to permanently preserve the six “beneficial public values” on all the watershed lands through conservation easements or equivalent protections, as well as to make approximately 40,000 acres of the watershed lands available for donation to qualified organizations.
The six “beneficial public values” being preserved by the LCC include: natural habitat of fish, wildlife, and plants; open space; outdoor recreation by the general public; sustainable forestry; agricultural uses; and historic values. The Utility’s goal is to implement all the LCC transactions by the end of 2023, subject to securing all required regulatory approvals.
The six “beneficial public values” being preserved by the LCC include: natural habitat of fish, wildlife, and plants; open space; outdoor recreation by the general public; sustainable forestry; agricultural uses; and historic values. The Utility’s goal is to implement all the LCC transactions by the first quarter of 2024, subject to securing all required regulatory approvals.
The term of the lease began on April 8, 2022 and the lease grants the Utility an option to purchase the legal parcel that contains the Lakeside Building. For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8.
The term of the lease began on April 8, 2022, and the lease grants the Utility an option to purchase the legal parcel that contains the Lakeside Building.
Removed
The Leaseback Agreement commenced on September 17, 2021 and continues through various dates for the various leased spaces, with December 31, 2023 being the latest lease expiration date.
Added
On July 11, 2023, the Utility and the Landlord (as defined in Note 2 of the Notes to the Consolidated Financial Statements in Item 8.) entered into an Amendment to Office Lease and an Agreement of Purchase and Sale and Joint Escrow Instructions, pursuant to which the Utility was deemed to have exercised its option to purchase the Property, as modified.
Removed
PG&E Corporation also leased approximately 42,000 square feet of office space from a third party in San Francisco, California. This lease expired, and the leased premises were surrendered at the end of February 2022. The Utility owns approximately 148,000 acres of land, including approximately 121,000 acres of watershed lands.
Added
The Utility will continue to lease the Property pursuant to the Lease, as amended, until closing in June 2025. For more information, see Note 2 of the Notes to the Consolidated Financial Statements in Item 8. The Utility owns approximately 135,000 acres of land, including approximately 100,000 acres of watershed lands.

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

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Biggest changeITEM 3. LEGAL PROCEEDINGS PG&E Corporation and the Utility are parties to various lawsuits and regulatory proceedings in the ordinary course of their business. For more information regarding material lawsuits and proceedings, see “Litigation Matters” in Item 7. MD&A, Item 1A.
Biggest changeITEM 3. LEGAL PROCEEDINGS PG&E Corporation and the Utility are parties to various lawsuits and regulatory proceedings in the ordinary course of their business. For more information regarding material lawsuits and proceedings, see “Litigation Matters” in Item 7. MD&A, Item 1A. Risk Factors and Notes 14 and 15 of the Notes to the Consolidated Financial Statements in Item 8 .
Removed
Risk Factors and Notes 2, 15, and 16 of the Notes to the Consolidated Financial Statements in Item 8 .

Item 4. Mine Safety Disclosures

Mine Safety Disclosures — required of mining issuers

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Biggest changeOctober 2014 to September 2017 Sumeet Singh 44 Executive Vice President, Chief Risk Officer and Chief Safety Officer, PG&E Corporation and Pacific Gas and Electric Company January 1, 2022 to present Senior Vice President and Chief Risk Officer, PG&E Corporation and Pacific Gas and Electric Company February 1, 2021 to December 31, 2021 Interim President and Chief Risk Officer, Pacific Gas and Electric Company; Senior Vice President and Chief Risk Officer, PG&E Corporation January 1, 2021 to January 31, 2021 Senior Vice President and Chief Risk Officer, PG&E Corporation and Pacific Gas and Electric Company August 2020 to December 31, 2021 Gas Safety & Integrity Officer, Energy, Picarro, Inc.
Biggest changeWilliams 41 Vice President, Chief Financial Officer and Controller, Pacific Gas and Electric Company January 10, 2023 to present Vice President, Finance and Planning January 2020 to January 10, 2023 Senior Director, Business Finance Electric Operations March 2019 to January 10, 2022 Director, Business Finance October 2014 to February 2019 Sumeet Singh 45 Executive Vice President, Operations and Chief Operating Officer, Pacific Gas and Electric Company March 1, 2023 to present Executive Vice President, Chief Risk and Chief Safety Officer, PG&E Corporation and Pacific Gas and Electric Company January 1, 2022 to February 28, 2023 Senior Vice President and Chief Risk Officer, PG&E Corporation and Pacific Gas and Electric Company February 1, 2021 to December 31, 2021 Interim President and Chief Risk Officer, Pacific Gas and Electric Company; Senior Vice President and Chief Risk Officer, PG&E Corporation January 1, 2021 to January 31, 2021 Senior Vice President and Chief Risk Officer, PG&E Corporation and Pacific Gas and Electric Company August 2020 to December 31, 2021 Gas Safety & Integrity Officer, Energy, Picarro, Inc.
ITEM 4. MINE SAFETY DISCLOSURES Not applicable. INFORMATION ABOUT OUR EXECUTIVE OFFICERS The following individuals serve as executive officers of PG&E Corporation, as of February 22, 2023. Except as otherwise noted, all positions have been held at PG&E Corporation. Name Age Positions Held Over Last Five Years Time in Position Patricia K.
ITEM 4. MINE SAFETY DISCLOSURES Not applicable. INFORMATION ABOUT OUR EXECUTIVE OFFICERS The following individuals serve as executive officers of PG&E Corporation, as of February 21, 2024. Except as otherwise noted, all positions have been held at PG&E Corporation. Name Age Positions Held Over Last Five Years Time in Position Patricia K.
Simon 58 Executive Vice President, General Counsel and Chief Ethics & Compliance Officer August 15, 2020 to present Executive Vice President, Law, Strategy, and Policy June 2019 to August 2020 56 Executive Vice President May 2019 to June 2019 Interim Chief Executive Officer January 2019 to May 2019 Executive Vice President and General Counsel March 2017 to January 2019 Executive Vice President, Corporate Services and Human Resources August 2015 to February 2017 Adam L.
Simon 59 Executive Vice President, General Counsel and Chief Ethics & Compliance Officer August 15, 2020 to present Executive Vice President, Law, Strategy, and Policy June 2019 to August 2020 Executive Vice President May 2019 to June 2019 Interim Chief Executive Officer January 2019 to May 2019 Executive Vice President and General Counsel March 2017 to January 2019 Executive Vice President, Corporate Services and Human Resources August 2015 to February 2017 56 Marlene M.
May 2016 to December 2018 Sumeet Singh 44 Executive Vice President, Chief Risk and Chief Safety Officer, PG&E Corporation and Pacific Gas and Electric Company January 1, 2022 to present Senior Vice President and Chief Risk Officer, PG&E Corporation and Pacific Gas and Electric Company February 1, 2021 to December 31, 2021 Interim President and Chief Risk Officer, Pacific Gas and Electric Company; Senior Vice President and Chief Risk Officer, PG&E Corporation January 1, 2021 to January 31, 2021 Senior Vice President and Chief Risk Officer, PG&E Corporation and Pacific Gas and Electric Company August 2020 to December 31, 2021 Gas Safety & Integrity Officer, Energy, Picarro, Inc.
May 2016 to December 2018 Sumeet Singh 45 Executive Vice President, Operations and Chief Operating Officer, Pacific Gas and Electric Company March 1, 2023 to present Executive Vice President, Chief Risk and Chief Safety Officer, PG&E Corporation and Pacific Gas and Electric Company January 1, 2022 to February 28, 2023 Senior Vice President and Chief Risk Officer, PG&E Corporation and Pacific Gas and Electric Company February 1, 2021 to December 31, 2021 Interim President and Chief Risk Officer, Pacific Gas and Electric Company; Senior Vice President and Chief Risk Officer, PG&E Corporation January 1, 2021 to January 31, 2021 Senior Vice President and Chief Risk Officer, PG&E Corporation and Pacific Gas and Electric Company August 2020 to December 31, 2021 Gas Safety & Integrity Officer, Energy, Picarro, Inc.
Glickman 42 Executive Vice President, Engineering, Planning, and Strategy May 3, 2021 to present Global Head of Utilities and Renewables, Bain & Company March 2020 to April 2021 Partner, Bain & Company January 2014 to April 2021 57 Consultant, Bain & Company August 2007 to December 2013 Stephanie N.
May 2016 to December 2018 Jason M. Glickman 43 Executive Vice President, Engineering, Planning, and Strategy May 3, 2021 to present Global Head of Utilities and Renewables, Bain & Company March 2020 to April 2021 Partner, Bain & Company January 2014 to April 2021 Consultant, Bain & Company August 2007 to December 2013 Stephanie N.
Poppe 54 Chief Executive Officer January 4, 2021 to present President and Chief Executive Officer, CMS Energy Corporation July 2016 to December 2020 Vice President, Customer Experience, Rates and Regulations, Consumers Energy Company January 2011 to July 2016 Christopher A.
Poppe 55 Chief Executive Officer January 4, 2021 to present President and Chief Executive Officer, CMS Energy Corporation July 2016 to December 2020 Vice President, Customer Experience, Rates and Regulations, Consumers Energy Company January 2011 to July 2016 Carolyn J.
Santos 62 Executive Vice President and Chief Customer Officer, Pacific Gas and Electric Company March 15, 2021 to present President, Gulf Power Company January 2019 to March 2021 Chief Integration Officer, NextEra Energy, Inc. March 2015 to December 2018 Jason M.
Santos 63 Executive Vice President and Chief Customer and Enterprise Solutions Officer, Pacific Gas and Electric Company October 16, 2023 to present Executive Vice President and Chief Customer Officer, Pacific Gas and Electric Company March 15, 2021 to October 15, 2023 President, Gulf Power Company January 2019 to March 2021 Chief Integration Officer, NextEra Energy, Inc.
Santos 62 Executive Vice President and Chief Customer Officer March 15, 2021 to present President, Gulf Power Company January 2019 to March 2021 Chief Integration Officer, NextEra Energy, Inc. March 2015 to December 2018 Jason M.
Santos 63 Executive Vice President and Chief Customer and Enterprise Solutions Officer, Pacific Gas and Electric Company October 16, 2023 to present Executive Vice President and Chief Customer Officer March 15, 2021 to October 15, 2023 President, Gulf Power Company January 2019 to March 2021 Chief Integration Officer, NextEra Energy, Inc.
February 2020 to August 2020 Senior positions within the Utility including Vice President, Asset, Risk Management and Community Wildfire Safety Program from May 2019 to January 2020, Vice President, Community Wildfire Safety Program, from September 2018 to May 2019, Vice President, Gas Asset and Risk Management from September 2015 to August 2018 September 2015 to January 2020 58 PART II
February 2020 to August 2020 58 Senior positions within the Utility including Vice President, Asset, Risk Management and Community Wildfire Safety Program from May 2019 to January 2020, Vice President, Community Wildfire Safety Program, from September 2018 to May 2019, Vice President, Gas Asset and Risk Management from September 2015 to August 2018 September 2015 to January 2020 Kaled Awada 49 Executive Vice President, Chief People Officer, PG&E Corporation and Pacific Gas and Electric Company January 16, 2024 to present Executive Vice President & Chief Human Resources Officer, Tenneco Inc.
Glickman 42 Executive Vice President, Engineering, Planning, and Strategy, Pacific Gas and Electric Company May 3, 2021 to present Global Head of Utilities and Renewables, Bain & Company March 2020 to April 2021 Partner, Bain & Company January 2014 to April 2021 Consultant, Bain & Company August 2007 to December 2013 The following individuals serve as executive officers of the Utility as of February 22, 2023.
Glickman 43 Executive Vice President, Engineering, Planning, and Strategy, Pacific Gas and Electric Company May 3, 2021 to present Global Head of Utilities and Renewables, Bain & Company March 2020 to April 2021 Partner, Bain & Company January 2014 to April 2021 Consultant, Bain & Company August 2007 to December 2013 Kaled Awada 49 Executive Vice President, Chief People Officer, PG&E Corporation and Pacific Gas and Electric Company January 16, 2024 to present Executive Vice President & Chief Human Resources Officer, Tenneco Inc.
Peterman 44 Executive Vice President, Corporate Affairs and Chief Sustainability Officer October 1, 2021 to present Executive Vice President, Corporate Affairs June 1, 2021 to September 30, 2021 Senior Vice President, Strategy and Regulatory Affairs, Southern California Edison September 2019 to May 2021 Commissioner, California Public Utilities Commission December 2012 to December 2018 Julius Cox 51 Executive Vice President, People, Shared Services and Supply Chain, PG&E Corporation and Pacific Gas and Electric Company February 1, 2021 to present Senior Vice President & Chief Human Resources Officer, American Electric Power October 2019 to January 2021 Executive Vice President & Chief Transformation Officer, Dynegy Inc.
Peterman 45 Executive Vice President, Corporate Affairs and Chief Sustainability Officer October 1, 2021 to present Executive Vice President, Corporate Affairs June 2021 to September 2021 Senior Vice President, Strategy and Regulatory Affairs, Southern California Edison September 2019 to May 2021 Commissioner, California Public Utilities Commission December 2012 to December 2018 Ajay Waghray 62 Executive Vice President and Chief Information Officer, PG&E Corporation and Pacific Gas and Electric Company January 1, 2024 to present Executive Vice President and Chief Information Officer, PG&E Corporation July 1, 2023 to December 31, 2023 Senior Vice President and Chief Information Officer September 21, 2020 to June 30, 2023 Founder, Agni Growth Ventures, LLC January 2019 to September 2021 Executive Vice President and Chief Technology Officer, Assurant Inc.
September 2017 to April 2018 Executive Vice President & Chief Administrative Officer, Dynegy Inc. October 2014 to September 2017 Ajay Waghray 61 Senior Vice President and Chief Information Officer September 21, 2020 to present Founder, Agni Growth Ventures, LLC January 2019 to September 2021 Executive Vice President and Chief Technology Officer, Assurant Inc.
March 2015 to December 2018 Ajay Waghray 62 Executive Vice President and Chief Information Officer, PG&E Corporation and Pacific Gas and Electric Company January 1, 2024 to present Executive Vice President and Chief Information Officer, PG&E Corporation July 1, 2023 to December 31, 2023 Senior Vice President and Chief Information Officer September 21, 2020 to June 30, 2023 Founder, Agni Growth Ventures, LLC January 2019 to September 2021 Executive Vice President and Chief Technology Officer, Assurant Inc.
Removed
Foster 44 Executive Vice President and Chief Financial Officer March 20, 2021 to present Vice President and Interim Chief Financial Officer September 26, 2020 to March 20, 2021 Vice President, Treasury and Investor Relations March 9, 2020 to September 25, 2020 Senior positions within PG&E Corporation’s Investor Relations department, including as its Vice President starting in December 2018 November 2017 to March 8, 2020 55 Senior positions within PG&E Corporation and the Utility, including Director, Integrated Grid Planning and Innovation from June 2016 to October 2017 September 2011 to October 2017 Carla J.
Added
Burke 56 Executive Vice President and Chief Financial Officer May 4, 2023 to present Chief Financial Officer & Executive Vice President, Chevron Phillips Chemical Company LLC February 2019 to September 2022 Senior positions, including Executive Vice President, Strategy & Administration, Dynegy, Inc. August 2011 to April 2018 55 Carla J.
Removed
Wright 45 Executive Vice President, Operations and Chief Operating Officer, Pacific Gas and Electric Company February 1, 2021 to present Chief Executive Officer and President, MidAmerican Energy Company January 2018 to January 26, 2021 President of MidAmerican Funding LLC January 2018 to January 26, 2021 Vice President, Gas Delivery, MidAmerican Energy Company May 2015 to January 2018 Vice President, Wind Generation & Development, MidAmerican Energy Company January 2012 to May 2015 Marlene M.
Added
September 2018 to November 2022 Global Vice President, Human Resources, Aptiv PLC May 2015 to August 2018 57 The following individuals serve as executive officers of the Utility as of February 21, 2024. Except as otherwise noted, all positions have been held at the Utility. Marlene M.
Removed
Except as otherwise noted, all positions have been held at the Utility. Adam L.
Added
September 2018 to November 2022 Global Vice President, Human Resources, Aptiv PLC May 2015 to August 2018 59 PART II
Removed
Wright 45 Executive Vice President, Operations and Chief Operating Officer February 1, 2021 to present Chief Executive Officer and President, MidAmerican Energy Company January 2018 to January 26, 2021 President of MidAmerican Funding LLC January 2018 to January 26, 2021 Vice President, Gas Delivery, MidAmerican Energy Company May 2015 to January 2018 Vice President, Wind Generation & Development, MidAmerican Energy Company January 2012 to May 2015 Marlene M.
Removed
Williams 40 Vice President, Chief Financial Officer and Controller, Pacific Gas and Electric Company January 10, 2023 to present Vice President, Finance and Planning January 2020 to January 10, 2023 Senior Director, Business Finance Electric Operations March 2019 to January 10, 2022 Director, Business Finance October 2014 to February 2019 Julius Cox 51 Executive Vice President, People, Shared Services and Supply Chain, PG&E Corporation and Pacific Gas and Electric Company February 1, 2021 to present Senior Vice President & Chief Human Resources Officer, American Electric Power October 2019 to January 2021 Executive Vice President & Chief Transformation Officer, Dynegy Inc.
Removed
September 2017 to April 2018 Executive Vice President & Chief Administrative Officer, Dynegy Inc.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

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Biggest changeMD&A and PG&E Corporation’s Consolidated Statements of Equity, the Utility’s Consolidated Statements of Shareholders’ Equity, and Note 8 of the Notes to the Consolidated Financial Statements in Item 8.
Biggest changeMD&A and PG&E Corporation’s Consolidated Statements of Equity, the Utility’s Consolidated Statements of Shareholders’ Equity, and Note 6 of the Notes to the Consolidated Financial Statements in Item 8. Share Exchanges On July 8, 2021, PG&E Corporation, the Utility, ShareCo and the Fire Victim Trust entered into the Share Exchange and Tax Matters Agreement.
On the dates and in the amounts set forth in the table below, the Fire Victim Trust exchanged a total of 290,000,000 Plan Shares, for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement; in each case, the Fire Victim Trust thereafter reported that it sold the applicable New Shares.
On the dates and in the amounts set forth in the table below, the Fire Victim Trust exchanged a total of 477,743,590 Plan Shares, for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement; in each case, the Fire Victim Trust thereafter reported that it sold the applicable New Shares.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES As of February 16, 2023, there were 43,782 holders of record of PG&E Corporation common stock.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES As of February 14, 2023, there were 42,199 holders of record of PG&E Corporation common stock.
Date Shares Exchanged January 31, 2022 40,000,000 April 14, 2022 60,000,000 October 4, 2022 35,000,000 October 27, 2022 35,000,000 December 12, 2022 60,000,000 January 9, 2023 60,000,000 Total Shares Exchanged 290,000,000 Each exchange was effected in reliance on the exemption from registration under Section 3(a)(10) of the Securities Act. See “Tax Matters” in Item 7.
Date Shares Exchanged January 1 - December 31, 2022 230,000,000 January 9, 2023 60,000,000 April 11, 2023 60,000,000 July 12, 2023 60,000,000 December 13, 2023 67,743,590 Total Shares Exchanged 477,743,590 Each exchange was effected in reliance on the exemption from registration under Section 3(a)(10) of the Securities Act. See “Tax Matters” in Item 7.
Removed
Share Exchanges On July 8, 2021, PG&E Corporation, the Utility, ShareCo and the Fire Victim Trust entered into the Share Exchange and Tax Matters Agreement, pursuant to which PG&E Corporation and the Utility made a “grantor trust” election for the Fire Victim Trust effective retroactively to the inception of the Fire Victim Trust.
Added
As of February 14, 2024, the Fire Victim Trust reported having sold all of the shares of PG&E Corporation common stock it had owned and no longer owning any shares.
Removed
As a result of the grantor trust election, shares of PG&E Corporation common stock owned by the Fire Victim Trust are treated as held by the Utility and, in turn attributed to PG&E Corporation for income tax purposes.

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

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Biggest changeFuture cash flow from operating activities will be affected by various factors, including: • the timing and amount of costs in connection with the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire and the timing and amount of any potential related insurance, Wildfire Fund, and regulatory recoveries; • the timing and amounts of costs, including fines and penalties, that may be incurred in connection with current and future enforcement, litigation, and regulatory matters (see “Wildfire-Related Securities Class Action” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8 and “Regulatory Matters” below for more information); • the severity, extent and duration of the global COVID-19 pandemic and its impact on the Utility’s service area, the ability of the Utility to collect on its customer receivables, the ability of the Utility’s customers to pay their utility bills in full and in a timely manner, the ability of the Utility to offset these effects, including with spending reductions, and the ability of the Utility to recover through rates any losses incurred in connection with the COVID-19 pandemic, as well as the impact of the COVID-19 pandemic on the availability or cost of financing; • the timing and amounts of available funds to pay eligible claims for liabilities arising from future wildfires; • the timing and amount of substantially increasing costs in connection with the 2020-2022 WMP and the costs previously incurred in connection with the 2019 WMP that are not currently being recovered through rates (see “Regulatory Matters” below for more information); 73 • the timing and amounts of available funds collected for self-insurance (see “2023 General Rate Case” in the Regulatory Matters section of Item 7.
Biggest changeThe Utility’s receipts from customers are expected to increase primarily as a result of increases in the Utility’s rate base. 72 Future cash flow from operating activities will be affected by various factors, including: • the timing and amount of costs in connection with the 2019 Kincade fire, the 2021 Dixie fire, and the 2022 Mosquito fire and the timing and amount of any potential related insurance, including funds available from self-insurance (see “2023 General Rate Case” in the “Regulatory Matters” section below for more information), the Wildfire Fund, and regulatory recoveries; • the timing and amount of costs in connection with future wildfires and the timing and amount of any potential related insurance, including funds available from self-insurance and the Wildfire Fund (see “Wildfire Fund under AB 1054” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8); • the timing and amount of costs in connection with the 2020-2022 and 2023-2025 WMPs and the costs previously incurred in connection with the 2019 WMP that are not currently being recovered through rates (see “Regulatory Matters” below for more information); • the timing and outcomes of the Utility’s pending and future ratemaking and regulatory proceedings, including the extent to which PG&E Corporation and the Utility are able to recover their costs through regulated rates as recorded in memorandum accounts or balancing accounts, or as otherwise requested; and • the timing and amount of electric commodity price volatility and differences between commodity costs and revenue collections.
PG&E Corporation’s and the Utility’s credit ratings may be affected by the ultimate outcome of pending enforcement and litigation matters. Credit rating downgrades may impact the cost and availability of short-term borrowings, including credit facilities, and long-term debt costs.
Credit Ratings PG&E Corporation’s and the Utility’s credit ratings may be affected by the ultimate outcome of pending enforcement and litigation matters. Credit rating downgrades may impact the cost and availability of short-term borrowings, including credit facilities, and long-term debt costs.
The costs addressed in this application reflect costs related to wildfire mitigation and certain catastrophic events, as well as implementation of various customer-focused initiatives. These costs were incurred primarily in 2021. 77 The recorded expenditures consist of $1.2 billion in expenses and $136 million in capital expenditures.
The costs addressed in this application reflect costs related to wildfire mitigation and certain catastrophic events, as well as implementation of various customer-focused initiatives. These costs were incurred primarily in 2021. The recorded expenditures consist of $1.2 billion in expenses and $136 million in capital expenditures.
The application proposes that the negotiated transaction documents would be submitted to the CPUC via an advice letter. On December 13, 2022, the Utility filed applications with a similar request with the FERC and also filed a related application with the FERC requesting the transfer of certain hydro licenses to Pacific Generation.
The application proposes that the negotiated transaction documents would be submitted to the CPUC via an advice letter. On December 13, 2022, the Utility and Pacific Generation filed an application with a similar request with the FERC and also filed a related application with the FERC requesting the transfer of certain hydro licenses to Pacific Generation.
On October 26, 2022, the Utility notified the CPUC that the Utility’s procedure for wood pole replacements did not comply with CPUC requirements for replacement of poles under certain conditions and, accordingly, in some instances, the Utility failed to replace wood poles with safety factors below the required minimum.
On October 26, 2022, the Utility notified the CPUC that the Utility’s procedure for wood pole replacements did not comply with CPUC requirements for replacement of poles under certain conditions and, in some instances, the Utility failed to replace wood poles with safety factors below the required minimum.
Application with Pacific Generation LLC for Approval to Transfer Non-Nuclear Generation Assets On September 28, 2022, the Utility filed an application with the CPUC regarding the separation of the Utility’s non-nuclear generation assets into a newly formed, stand-alone Utility subsidiary, Pacific Generation.
Application with Pacific Generation for Approval to Transfer Non-Nuclear Generation Assets On September 28, 2022, the Utility filed an application with the CPUC regarding the separation of the Utility’s non-nuclear generation assets into a newly formed, stand-alone Utility subsidiary, Pacific Generation.
These accounts, which include the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, and RTBA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, and other wildfire prevention-related costs.
These accounts, which include the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, RTBA, and MGMA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, and other wildfire prevention-related costs.
The CPUC authorizes the Utility’s capital structure, the aggregate amount of long-term and short-term debt that the Utility may issue, and the revenue requirements the Utility is able to collect to recover its cost of capital.
The CPUC authorizes the Utility’s capital structure, the aggregate amount of long-term and short-term debt that the Utility may issue, and the revenue requirements the Utility is able to collect to recover its cost of service.
The CPUC may also authorize balancing accounts with limitations or caps to cost recovery. These accounts, which include the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, and RTBA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, other wildfire prevention-related costs, certain third-party wildfire claims, and insurance costs.
The CPUC may also authorize balancing accounts with limitations or caps on cost recovery. These accounts, which include the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, RTBA, and MGMA among others, allow the Utility to track the costs associated with work related to disaster and wildfire response, other wildfire prevention-related costs, certain third-party wildfire claims, and insurance costs.
See Item 1A. Risk Factors, “Environmental Regulation” in Item 1. and “Environmental Remediation Contingencies” in Note 16 of the Notes to the Consolidated Financial Statements in Item 8. RISK MANAGEMENT ACTIVITIES PG&E Corporation, mainly through its ownership of the Utility, and the Utility are exposed to risks associated with adverse changes in commodity prices, interest rates, and counterparty credit.
See Item 1A. Risk Factors, “Environmental Regulation” in Item 1 and “Environmental Remediation Contingencies” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8. RISK MANAGEMENT ACTIVITIES PG&E Corporation, mainly through its ownership of the Utility, and the Utility are exposed to risks associated with adverse changes in commodity prices, interest rates, and counterparty credit.
While PG&E Corporation and the Utility believe that the assumptions used are appropriate, significant differences in actual experience, plan changes or amendments, or significant changes in assumptions may materially affect the recorded pension and other postretirement benefit obligations and future plan expenses. See Note 13 of the Notes to the Consolidated Financial Statements in Item 8.
While PG&E Corporation and the Utility believe that the assumptions used are appropriate, significant differences in actual experience, plan changes or amendments, or significant changes in assumptions may materially affect the recorded pension and other postretirement benefit obligations and future plan expenses. See Note 12 of the Notes to the Consolidated Financial Statements in Item 8.
The process for estimating wildfire-related liabilities requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. See Note 15 of the Notes to the Consolidated Financial Statements in Item 8.
The process for estimating wildfire-related liabilities requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. See Note 14 of the Notes to the Consolidated Financial Statements in Item 8.
The Utility’s undiscounted future costs could increase to as much as $2.3 billion if the extent of contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able to contribute to these costs and could increase further if the Utility chooses to remediate beyond regulatory requirements.
The Utility’s undiscounted future costs could increase to as much as $2.4 billion if the extent of contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able to contribute to these costs and could increase further if the Utility chooses to remediate beyond regulatory requirements.
Application for Second AB 1054 Securitization Transaction AB 1054 provides that the first $5.0 billion expended in the aggregate by California’s three large electric IOUs on fire risk mitigation capital expenditures included in their respective approved WMPs will be excluded from their respective equity rate bases.
Application for Third AB 1054 Securitization Transaction AB 1054 provides that the first $5.0 billion expended in the aggregate by California’s three large electric IOUs on fire risk mitigation capital expenditures included in their respective approved WMPs will be excluded from their respective equity rate bases.
The Utility recognizes such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. The amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Act.
The Utility recognizes such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. The amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the TCJA.
See Note 11 of the Notes to the Consolidated Financial Statements in Item 8 for further discussion of price risk management activities. Interest Rate Risk Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates.
See Note 10 of the Notes to the Consolidated Financial Statements in Item 8 for further discussion of price risk management activities. Interest Rate Risk Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates.
These costs may result from catastrophic events, changes in regulation, or extraordinary changes in operating practices. The Utility may seek authority to track incremental costs in a memorandum account and the CPUC may authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred.
For instance, these costs may result from catastrophic events, changes in regulation, or extraordinary changes in operating practices. The Utility may seek authority to track incremental costs in a memorandum account and the CPUC may authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred.
See Notes 3 and 4 of the Notes to the Consolidated Financial Statements in Item 8. To estimate its liability, the Utility uses a discounted cash flow model based upon significant estimates and assumptions about future decommissioning costs, inflation rates, and the estimated date of decommissioning.
See Notes 2 and 3 of the Notes to the Consolidated Financial Statements in Item 8. To estimate its liability, the Utility uses a discounted cash flow model based upon significant estimates and assumptions about future decommissioning costs, inflation rates, and the estimated date of decommissioning.
The Utility’s cost recovery proceedings for the costs described above that are pending, have pending appeals, or were completed during the year ended December 31, 2022 are summarized in the following table: Proceeding Request Status 2020 WMCE Revenue requirement of approximately $1.28 billion Settlement agreement to recover $1.04 billion of revenue requirement approved February 2023. 2021 WMCE Revenue requirement of approximately $1.47 billion Partial settlement agreement to recover $721 million of revenue requirement filed January 2022.
The Utility’s cost recovery proceedings for the costs described above that are pending, have pending appeals, or were completed during the year ended December 31, 2023 are summarized in the following table: Proceeding Request (1) Status 2020 WMCE Revenue requirement of approximately $1.28 billion Settlement agreement to recover $1.04 billion of revenue requirement approved February 2023. 2021 WMCE Revenue requirement of approximately $1.47 billion Partial settlement agreement to recover $721 million of revenue requirement approved August 2023. 2022 WMCE Revenue requirement of approximately $1.29 billion Filed December 2022.
See “2021 Dixie Fire,” and “2022 Mosquito Fire” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8 for more information. • The Timing and Outcome of Ratemaking and Other Proceedings. Regulatory ratemaking proceedings are a key aspect of the Utility’s business.
See “2021 Dixie Fire,” and “2022 Mosquito Fire” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8 for more information. • The Timing and Outcome of Ratemaking and Other Proceedings. Regulatory ratemaking proceedings are a key aspect of the Utility’s business.
Further, the facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program from time to time.
Further, the facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program.
Actual results may differ materially from these estimates and assumptions. See Note 15 and Note 16 of the Notes to the Consolidated Financial Statements in Item 8. Loss Recoveries PG&E Corporation and the Utility have recovery mechanisms available for wildfire liabilities including from insurance, through rates, and from the Wildfire Fund.
Actual results may differ materially from these estimates and assumptions. See Note 14 and Note 15 of the Notes to the Consolidated Financial Statements in Item 8. 87 Loss Recoveries PG&E Corporation and the Utility have recovery mechanisms available for wildfire liabilities including from insurance, through rates, and from the Wildfire Fund.
PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed under “Purchase Commitments” in Note 16 of the Notes to the Consolidated Financial Statements in Item 8.
PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed under “Purchase Commitments” in Note 15 of the Notes to the Consolidated Financial Statements.
The Inflation Reduction Act includes a 15% corporate alternative minimum tax (“CAMT”) on the adjusted financial statement income (“AFSI”) of corporations with average AFSI exceeding $1.0 billion over a three-year period, effective January 1, 2023. The law also extends and modifies existing tax credits and creates new tax credits for renewable and clean energy sources.
The Inflation Reduction Act includes a 15% corporate alternative minimum tax on the adjusted financial statement income (“AFSI”) of corporations with average AFSI exceeding $1.0 billion over a three-year period, effective January 1, 2023. The law also extends and modifies existing tax credits and creates new tax credits for qualifying investments on renewable and clean energy sources and energy storage.
At December 31, 2022 and 2021, if interest rates changed by one percent for all PG&E Corporation and Utility variable rate long-term debt, short-term debt, and cash investments, the pre-tax impact on net income over the next 12 months would be $54 million and $76 million, respectively, based on net variable rate debt and other interest rate-sensitive instruments outstanding.
At December 31, 2023 and 2022, if interest rates changed by one percent for all PG&E Corporation and Utility variable rate long-term debt, short-term debt, and cash investments, the pre-tax impact on net income over the next 12 months would be $57 million and $54 million, respectively, based on net variable rate debt and other interest rate-sensitive instruments outstanding.
At various dates throughout 2022, the Fire Victim Trust exchanged Plan Shares for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement; in each case, the Fire Victim Trust thereafter reported that it sold the applicable New Shares.
At various dates throughout 2022 and 2023, the Fire Victim Trust exchanged Plan Shares for an equal number of New Shares in the manner contemplated by the Share Exchange and Tax Matters Agreement; the Fire Victim Trust thereafter reported that it sold the applicable New Shares.
In the Original Application, the Utility proposed a series of safety, resiliency, and clean energy investments to further reduce wildfire risk and deliver safe, reliable, and clean energy service. Between August 2021 and January 2022, the Utility served various updates to its 2023 GRC testimony.
In the application, the Utility proposed a series of safety, resiliency, and clean energy investments to further reduce wildfire risk and deliver safe, reliable, and clean energy service. Between August 2021 and December 2022, the Utility served various updates to its 2023 GRC testimony.
In recognition of continued high inflation in health care costs and given the design of PG&E Corporation’s plans, the assumed health care cost trend rate for 2023 was 6.5%, gradually decreasing to the ultimate trend rate of approximately 4.5% in 2031 and beyond.
In recognition of continued high inflation in health care costs and given the design of PG&E Corporation’s plans, the assumed health care cost trend rate for 2024 was 6.3%, gradually decreasing to the ultimate trend rate of approximately 4.5% in 2031 and beyond.
In the 2023 GRC, the CPUC will determine the annual amount of base revenues that the Utility will be authorized to collect from customers from 2023 through 2026 to recover its anticipated costs for gas distribution, gas transmission and storage, electric distribution, and electric generation and to provide the Utility an opportunity to earn its authorized rate of return.
In the 2023 GRC, the CPUC determined the annual amount of base revenues that the Utility will be authorized to collect from customers from 2023 through 2026 (the “GRC period”) to recover its anticipated costs for gas distribution, gas transmission and storage, electric distribution, and electric generation and to provide the Utility an opportunity to earn its authorized rate of return.
Additionally, the Utility’s future cash flows from financing activities will be affected by the timing and outcome of future AB 1054 securitization transactions, the timing and outcome of the potential sale of a minority interest in Pacific Generation to one or more investors to be identified, dividend payments, and equity contributions from PG&E Corporation.
Additionally, the Utility’s future cash flows from financing activities will be affected by the timing and outcome of the potential sale of a minority interest in Pacific Generation to one or more investors to be identified, dividend payments, and equity contributions from PG&E Corporation.
The Utility recovers these costs in its GRC through fixed reservation charges and volumetric charges from long-term contracts, resulting in price and volumetric risk. The Utility uses value-at-risk to measure its shareholders’ exposure to these risks. The Utility’s value-at-risk was approximately $3 million and $5 million at December 31, 2022 and 2021, respectively.
The Utility recovers these costs in its GRC through fixed reservation charges and volumetric charges from long-term contracts, resulting in price and volumetric risk. The Utility uses value-at-risk to measure its shareholders’ exposure to these risks. The Utility’s value-at-risk was approximately $4 million and $3 million at December 31, 2023 and 2022, respectively.
See Note 4 of the Notes to the Consolidated Financial Statements in Item 8. 95 The pension and other postretirement benefit obligations are calculated using actuarial models as of the December 31 measurement date.
See Note 3 of the Notes to the Consolidated Financial Statements in Item 8. The pension and other postretirement benefit obligations are calculated using actuarial models as of the December 31 measurement date.
Finally, recoveries for the 2019 Kincade fire would be subject to a 40% limitation on the allowed amount of claims arising before emergence from bankruptcy. As of December 31, 2022, the Utility has recorded a Wildfire Fund receivable of $175 million for the 2021 Dixie fire.
Finally, recoveries for the 2019 Kincade fire would be subject to a 40% limitation on the allowed amount of claims arising before emergence from bankruptcy. As of December 31, 2023, the Utility has recorded a Wildfire Fund receivable of $600 million for the 2021 Dixie fire.
As of December 31, 2022, PG&E Corporation and the Utility had recorded aggregate liabilities of $1.025 billion, $400 million, $1.175 billion, and $100 million for claims in connection with the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire, respectively, and in each case before available insurance, and, in the case of the 2021 Dixie fire and the 2022 Mosquito fire, other probable cost recoveries.
As of December 31, 2023, PG&E Corporation and the Utility had recorded aggregate liabilities of $1.125 billion, $400 million, $1.6 billion, and $100 million for claims in connection with the 2019 Kincade fire, the 2020 Zogg fire, the 2021 Dixie fire, and the 2022 Mosquito fire, respectively, and in each case before available insurance, and, in the case of the 2021 Dixie fire and the 2022 Mosquito fire, other probable cost recoveries.
The application also requested that the CPUC exclude the securitized debt from the Utility’s ratemaking capital structure and adjust the Utility’s 2020 GRC revenue requirements following the issuance of the recovery bonds.
The application also requested that the CPUC exclude the securitized debt from the Utility’s ratemaking capital structure and adjust the Utility’s 2020 GRC, 2020 WMCE proceeding, and 2023 GRC revenue requirements following the issuance of the recovery bonds.
The following table summarizes the Utility’s energy procurement credit risk exposure to its counterparties: Exposure (1) (in millions) Number of Wholesale Customers or Counterparties >10% Net Credit Exposure to Wholesale Customers or Counterparties >10% (in millions) December 31, 2022 $ 814 1 $ 162 December 31, 2021 $ 570 1 $ 63 (1) Exposure is the positive exposure maximum that equals mark-to-market value on physically and financially settled contracts, plus net receivables (payables) where netting is contractually allowed minus collateral posted by counterparties and held by the Utility plus collateral posted by the Utility and held by the counterparties.
The following table summarizes the Utility’s energy procurement credit risk exposure to its counterparties: Exposure (1) (in millions) Number of Wholesale Customers or Counterparties >10% Net Credit Exposure to Wholesale Customers or Counterparties >10% (in millions) December 31, 2023 $ 926 3 $ 457 December 31, 2022 $ 814 1 $ 162 (1) Exposure is the positive exposure maximum that equals mark-to-market value on physically and financially settled contracts, plus net receivables (payables) where netting is contractually allowed minus collateral posted by counterparties and held by the Utility plus collateral posted by the Utility and held by the counterparties.
See below for more information. 66 Cost of Electricity The Utility’s cost of electricity includes the cost of power purchased from third parties (including renewable energy resources), fuel and associated transmission costs used in its own generation facilities, fuel and associated transmission costs supplied to other facilities under power purchase agreements, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities.
Cost of Electricity The Utility’s cost of electricity includes the cost of power purchased from third parties (including renewable energy resources), fuel and associated transmission costs used in its own generation facilities, fuel and associated transmission costs supplied to other facilities under power purchase agreements, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities.
Because rate recovery may require CPUC authorization for these accounts, there can be a delay between when the Utility incurs costs and when it may recover those costs. As of December 31, 2022, the Utility had recorded an aggregate amount of approximately $6.2 billion in costs for the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, MGMA, and RTBA.
Because rate recovery may require CPUC authorization for these accounts, there can be a delay between when the Utility incurs costs and when it may recover those costs. As of December 31, 2023, the Utility had recorded an aggregate amount of approximately $4.8 billion in costs for the CEMA, WEMA, FHPMA, FRMMA, WMPMA, VMBA, WMBA, RTBA, and MGMA.
There were fires in the Utility’s and other participating utilities’ services territories since July 12, 2019, including fires for which the cause is unknown, which may in the future be determined to be covered by the Wildfire Fund.
There were fires in the Utility’s and other participating utilities’ service areas since July 12, 2019, including fires for which the cause is unknown, which may in the future be determined to be covered by the Wildfire Fund.
During the years ended December 31, 2022 and 2021, the Utility recorded amortization and accretion expense of $477 million and $517 million, respectively. The amortization of the asset, accretion of the liability, and acceleration of the amortization of the asset is reflected in Wildfire Fund expense in the Consolidated Statements of Income.
During the years ended December 31, 2023 and 2022, the Utility recorded amortization and accretion expense of $567 million and $477 million, respectively. The amortization of the asset, accretion of the liability, and acceleration of the amortization of the asset is reflected in Wildfire Fund expense in the Consolidated Statements of Income.
As of December 31, 2022, the Utility has recorded receivables for regulatory recovery of $503 million for the 2021 Dixie fire and $60 million for the 2022 Mosquito fire.
As of December 31, 2023, the Utility has recorded receivables for regulatory recovery of $561 million for the 2021 Dixie fire and $60 million for the 2022 Mosquito fire.
On December 22, 2022, the Utility submitted an update to the CPUC explaining the Utility had identified a population of wood poles that had not received intrusive inspections in accordance with GO 165’s deadlines due to legacy issues, which should no longer be an issue due to changes in Utility procedures.
On December 22, 2022 and February 1, 2024, the Utility submitted updates to the CPUC explaining the Utility had identified a population of wood poles that had not received intrusive inspections in accordance with GO 165’s deadlines due to legacy issues, which should no longer be an issue due to changes in Utility procedures.
The Utility generally utilizes retained earnings, equity contributions from PG&E Corporation and long-term debt issuances to maintain its CPUC-authorized long-term capital structure consisting of 52% equity and 48% debt and preferred stock and relies on short-term debt, including its revolving credit facilities, to fund temporary financing needs.
The Utility generally utilizes retained earnings, equity contributions from PG&E Corporation and long-term debt issuances to maintain its CPUC-authorized long-term capital structure consisting of 52% common equity, 47.5% long-term debt, and 0.5% preferred equity and relies on short-term debt, including its revolving credit facilities, to fund temporary financing needs.
In recent years, decisions in GRC proceedings have been delayed. Delayed decisions may cause the Utility to develop its budgets based on approved revenue requirements and possible outcomes, rather than authorized amounts.
In recent years, decisions in GRC proceedings have been delayed. Delayed decisions may cause the Utility to develop its budgets based on possible outcomes, rather than authorized amounts.
The Utility could face fines, penalties, enforcement action, or other adverse legal or regulatory consequences for the late inspections or other noncompliance related to wildfire mitigation efforts. See “Self-Reports to the CPUC” in “Regulatory Matters” below. Despite these extensive measures, the potential that the Utility’s equipment will be involved in the ignition of future wildfires, including catastrophic wildfires, is significant.
The Utility could face fines, penalties, enforcement action, or other adverse legal or regulatory consequences for late inspections or other noncompliance related to wildfire mitigation efforts. Despite these extensive measures, the potential that the Utility’s equipment will be involved in the ignition of future wildfires, including catastrophic wildfires, is significant.
The Utility recognized pre-tax charges of $225 million related to the 2019 Kincade fire, $100 million related to the 2022 Mosquito fire, $25 million related to the 2021 Dixie fire, and $25 million related to the 2020 Zogg fire in the year ended December 31, 2022.
The Utility recognized pre-tax charges of $225 million related to the 2019 Kincade fire, $100 million related to the 2022 Mosquito fire, $25 million related to the 2021 Dixie fire, and $25 million related to the 2020 Zogg fire in 2022.
The settlement agreement does not address $591.9 million recorded to the VMBA, for which cost recovery will be determined separately by the CPUC. 2022 WMCE Application On December 15, 2022, the Utility filed an application with the CPUC requesting cost recovery of approximately $1.36 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.29 billion (the “2022 WMCE application”).
The settlement agreement did not address the Utility’s revenue requirement of $592 million associated with costs recorded to the VMBA, for which cost recovery will be determined separately by the CPUC. 2022 WMCE Application On December 15, 2022, the Utility filed an application with the CPUC requesting cost recovery of approximately $1.36 billion of recorded expenditures, resulting in a proposed revenue requirement of approximately $1.29 billion (the “2022 WMCE application”).
See “Wildfire Fund under AB 1054” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8. The Utility will be permitted to recover its wildfire-related claims and legal fees through rates only if the CPUC or the FERC, as applicable, determines that the Utility has met the prudency standard.
See “Wildfire Fund under AB 1054” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8. The Utility will be permitted to recover its wildfire-related claims in excess of insurance and legal fees through rates unless the CPUC or the FERC, as applicable, determines that the Utility has not met the applicable prudency standard.
For the Utility’s defined benefit pension plan, the assumed return of 6.1% compares to a ten-year actual return of 5.8%. The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of approximately 848 Aa-grade non-callable bonds at December 31, 2022.
For the Utility’s defined benefit pension plan, the assumed return of 6.0% compares to a ten-year actual return of 5.3%. The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of approximately 858 Aa-grade non-callable bonds at December 31, 2023.
Although the Utility believes that it has complied substantially with these requirements, it is undertaking a review and has identified instances of noncompliance. The Utility intends to update the CPUC and OEIS as its review progresses.
Although the Utility believes that it has complied substantially with these requirements, it continually reviews and has identified instances of noncompliance. The Utility intends to update the CPUC and the OEIS as its review progresses.
LITIGATION MATTERS PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to the enforcement and litigation matters described in Note 2, Note 15, and 16 of the Notes to the Consolidated Financial Statements in Item 8 that are incorporated by reference herein.
LITIGATION MATTERS PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to the enforcement and litigation matters described in Notes 14 and 15 of the Notes to the Consolidated Financial Statements in Item 8 and in “Regulatory Matters” below that are incorporated by reference herein.
The following table provides a summary of net income (loss) available for common shareholders: (in millions) 2022 2021 Consolidated Total $ 1,800 $ (102) PG&E Corporation (412) (226) Utility 2,212 124 PG&E Corporation’s net loss primarily consists of income taxes and interest expense on long-term debt.
The following table provides a summary of net income (loss) available for common shareholders: (in millions) 2023 2022 Consolidated Total $ 2,242 $ 1,800 PG&E Corporation (288) (412) Utility 2,530 2,212 PG&E Corporation’s net loss primarily consists of income taxes and interest expense on long-term debt.
The Utility’s total purchased power is driven by customer demand, net CAISO electricity market activities (purchases or sales), the availability of the Utility’s own generation facilities (including Diablo Canyon and its hydroelectric plants), and the cost-effectiveness of each source of electricity. The cost of electricity decreased in 2022 as compared to 2021.
The Utility’s total purchased power is driven by customer demand, net CAISO electricity market activities (purchases or sales), the availability of the Utility’s own generation facilities (including Diablo Canyon and its hydroelectric plants), and the cost-effectiveness of each source of electricity.
The 2023 cost of capital application also requested that the CPUC approve an upward adjustment above the three-month commercial paper rate for interest on the Utility’s balancing and memorandum accounts to reflect the Utility’s actual cost of short-term debt.
On January 16, 2024, the Utility submitted its response. The 2023 cost of capital application also requested that the CPUC approve an upward adjustment above the three-month commercial paper rate for interest on the Utility’s balancing and memorandum accounts to reflect the Utility’s actual cost of short-term debt.
If the ARC finds that the Utility did not substantially comply with the WMP during the 2020 compliance period, the CPUC is required to issue penalties for the finding of noncompliance.
If the court sustains the ARC’s finding that the Utility did not substantially comply with the WMP during the 2020 compliance period, the CPUC is required to issue penalties for the finding of noncompliance.
The Utility requested that the adjustment be set on an annual basis effective January 1 of each year based on the average difference between the three-month commercial paper rate and the Utility’s actual cost of short-term debt over the preceding twelve-month period from November through October.
The Utility requested that the adjustment be set on an annual basis effective January 1 of each year based on the average difference between the three-month commercial paper rate and the Utility’s actual cost of short-term debt over the preceding twelve-month period from November through October. The decision deferred consideration of the proposal to a second phase of the proceeding.
Credit Facilities As of December 31, 2022, PG&E Corporation and the Utility had $500 million and $1.5 billion available under their respective $500 million and $4.4 billion revolving credit facilities. The Utility also has access to the Receivables Securitization Program, under which the Utility may borrow the lesser of the facility limit and the facility availability.
Credit Facilities and Term Loans As of December 31, 2023, PG&E Corporation and the Utility had $500 million and $2.0 billion available under their respective $500 million and $4.4 billion revolving credit facilities. The Utility also has access to the Receivables Securitization Program, under which the Utility may borrow the lesser of the facility limit and the facility availability.
See “Loss Recoveries” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8 below. In addition to the probable wildfire-related recoveries noted above, the Utility has recorded $125 million of probable recoveries through FERC TO formula rates, which are recorded as a reduction to regulatory liabilities and are not captured in wildfire-related claims. See Item 1A.
In addition to the probable wildfire-related recoveries noted above, the Utility has recorded $99 million of probable recoveries through FERC TO formula rates, which are recorded as a reduction to regulatory liabilities and are not captured in wildfire-related claims. See Item 1A. Risk Factors and Note 14 of the Notes to the Consolidated Financial Statements in Item 8.
Cost of electricity also includes net sales (Utility owned generation and third parties) in the CAISO electricity markets. See Note 11 of the Notes to the Consolidated Financial Statements in Item 8.
See Note 10 of the Notes to the Consolidated Financial Statements in Item 8. Cost of electricity also includes net energy sales (Utility owned and third parties’ generation) in the CAISO electricity markets and directly with third parties.
See “Liquidity and Financial Resources” in Item 7 of the 2021 Form 10-K for discussion of the Utility’s cash flows for 2021 compared to 2020.
The following discussion presents the Utility’s cash flows for 2023 and 2022. See “Liquidity and Financial Resources” in Item 7 of the 2022 Form 10-K for discussion of the Utility’s cash flows for 2022 compared to 2021.
During this period, the laws governing the remediation process may change, as well as site conditions, thereby possibly affecting the cost of the remediation effort. As of December 31, 2022 and 2021, the Utility’s accruals for undiscounted gross environmental liabilities were $1.3 billion each.
During this period, the laws governing the remediation process may change, as well as site conditions, which could affect the cost of the remediation effort. As of December 31, 2023 and 2022, the Utility’s accruals for undiscounted gross environmental liabilities were $1.3 billion each.
On December 19, 2022, the CPUC issued a final decision. The final decision will reduce the NEM subsidy by, in large part, reducing the bill credits for exported energy to avoided cost levels for new customers interconnecting under the successor tariff established by the final decision.
The final decision will reduce the NEM subsidy by, in large part, reducing the bill credits for exported energy to avoided cost levels for new customers interconnecting under the successor tariff established by the final decision.
The Utility has liability insurance from various insurers, which provides coverage for third-party claims. PG&E Corporation and the Utility record a receivable for a recovery when it is deemed probable that recovery of a recorded loss will occur and they can reasonably estimate the amount or its range.
The Utility has liability insurance from various insurers, which provides coverage for third-party claims arising before August 1, 2023. PG&E Corporation and the Utility record a receivable for a recovery when they determine that it is probable that they will recover a recorded loss and they can reasonably estimate the amount or its range.
PG&E Corporation and the Utility may be able to mitigate the financial impact of future wildfires in excess of insurance coverage through the Wildfire Fund, or cost recovery through rates. Each of these mitigations involves uncertainties, and liabilities could exceed available recoveries.
PG&E Corporation and the Utility may be able to mitigate the financial impact of future wildfires in excess of insurance coverage through the Wildfire Fund, or cost recovery through rates. Each of these mitigations involves uncertainties, and liabilities could exceed available recoveries. See “Loss Recoveries” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8.
In response to the wildfire threat facing California, PG&E Corporation and the Utility have taken aggressive steps to mitigate the threat of catastrophic wildfires. The Utility’s wildfire mitigation initiatives include EPSS, PSPS, vegetation management, asset inspections, and system hardening. In particular, in 2022 the Utility expanded the EPSS program to all high fire risk areas.
In response to the wildfire threat facing California, PG&E Corporation and the Utility have taken aggressive steps to mitigate the threat of catastrophic wildfires. The Utility’s wildfire mitigation initiatives include EPSS, PSPS, vegetation management, asset inspections, and system hardening.
The proceeds were used for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement. On January 6, 2023, the Utility completed the sale of (i) $750 million aggregate principal amount of 6.150% First Mortgage Bonds due 2033 and (ii) $750 million aggregate principal amount of 6.750% First Mortgage Bonds due 2053.
The net proceeds were used for the repayment of borrowings outstanding under the Utility’s revolving credit facility pursuant to the Utility Revolving Credit Agreement. On March 30, 2023, the Utility completed the sale of $750 million aggregate principal amount of 6.70% First Mortgage Bonds due 2053.
If the Utility’s spending during the period of the delay is less than the authorized amount, the Utility could be exposed to operational and financial risk associated with the lower level of work achieved compared to that funded by the CPUC. Except as otherwise noted, the Utility is unable to predict the timing and outcome of the following applications.
If the Utility’s spending during the period of the delay is less than the authorized amount, the Utility could be exposed to operational and financial risk associated with the lower level of work achieved compared to that funded by the CPUC.
Of these costs, approximately $856 million was authorized for recovery and accounted for as current, and $5.3 billion was accounted for as long term as of December 31, 2022. See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.
Of these costs, approximately $1.2 billion was authorized for recovery and accounted for as current, and $3.6 billion was accounted for as long term as of December 31, 2023. See Note 3 of the Notes to the Consolidated Financial Statements in Item 8.
The estimated future cash flows are discounted using a credit-adjusted risk-free rate that reflects the risk associated with the decommissioning obligation. At December 31, 2022, the Utility’s recorded ARO for the estimated cost of retiring these long-lived assets was approximately $5.9 billion. Changes in these estimates and assumptions could materially affect the amount of the recorded ARO for these assets.
The estimated future cash flows are discounted using a credit-adjusted risk-free rate that reflects the risk associated with the decommissioning obligation. At December 31, 2023, the Utility’s recorded ARO for the estimated cost of retiring these long-lived assets was approximately $5.5 billion.
The facility limit fluctuates between $1.0 billion and $1.5 billion depending on the periods set forth in the amendment.
The facility limit fluctuates between $1.25 billion and $1.5 billion depending on the periods set forth in the transaction documents.
For more information on incurred expenditures, see Note 4 of the Notes to the Consolidated Financial Statements in Item 8. The extent to which the Utility will be able to recover these expenditures and other potential costs through rates is uncertain.
PG&E Corporation and the Utility have incurred and will continue to incur substantial expenditures in connection with these initiatives. For more information on incurred expenditures, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8. The extent to which the Utility will be able to recover these expenditures and other potential costs through rates is uncertain.
See Note 5 of the Notes to the Consolidated Financial Statements in Item 8 for further discussion of interest rates. 90 Energy Procurement Credit Risk The Utility conducts business with counterparties mainly in the energy industry to purchase electricity or gas and related services, including the CAISO market, other California IOUs, municipal utilities, energy trading companies, pipelines, financial institutions, electricity generation companies, and oil and natural gas production companies located in the United States and Canada.
Energy Procurement Credit Risk The Utility conducts business with counterparties mainly in the energy industry to purchase electricity or gas and related services, including the CAISO market, other California IOUs, municipal utilities, energy trading companies, pipelines, financial institutions, electricity generation companies, and oil and natural gas production companies located in the United States and Canada.
Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures. The Utility estimates that it will incur between $7.9 billion and $11.2 billion in 2023.
Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures. The Utility estimates that it will incur $10.4 billion of capital expenditures in 2024.
While the Utility generally expects such costs to be recoverable, there can be no assurance that the CPUC will authorize the Utility to recover the full amount of its costs. In recent years, the amount of the costs recorded in these accounts has increased.
While the Utility generally expects such costs to be recoverable, the CPUC may authorize the Utility to recover less than the full amount of its costs. In recent years, the amount of the costs recorded in these accounts has increased.
See “Key Factors Affecting Financial Results” above for further discussion about factors that could affect future results of operations. See “Results of Operations” in Item 7 of the 2021 Form 10-K for discussion of results of operations for 2021 compared to 2020.
RESULTS OF OPERATIONS The following discussion presents PG&E Corporation’s and the Utility’s operating results for 2023 and 2022. See “Key Factors Affecting Financial Results” above for further discussion about factors that could affect future results of operations. See “Results of Operations” in Item 7 of the 2022 Form 10-K for discussion of results of operations for 2022 compared to 2021.
The 364-Day 2022B Tranche Loans and the 2-Year 2022B Tranche Loans bear interest based on the Utility’s election of either (1) the Term Secured Overnight Financing Rate (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.25%, or (2) the base rate plus an applicable margin of 0.25%.
The 364-day tranche loan bears interest based on the Utility’s election of either (1) Term Secured Overnight Financing Rate (“SOFR”) (plus a 0.10% credit spread adjustment) plus an applicable margin of 1.375%, or (2) the alternate base rate plus an applicable margin of 0.375%.
See “Loss Recoveries” in Note 15 of the Notes to the Consolidated Financial Statements in Item 8. 93 Environmental Remediation Liabilities The Utility is subject to loss contingencies pursuant to federal and California environmental laws and regulations that in the future may require the Utility to pay for environmental remediation at sites where it has been, or may be, a potentially responsible party.
Environmental Remediation Liabilities The Utility is subject to loss contingencies pursuant to federal and California environmental laws and regulations that in the future may require the Utility to pay for environmental remediation at sites where it has been, or may be, a potentially responsible party.
The $1.7 billion reflected $212 million recorded and $1.16 billion forecasted capital expenditure amounts that were approved by the CPUC in the 2020 GRC and up to $350 million capital expenditure amounts pending in the 2020 WMCE proceeding.
The $1.38 billion reflected $187 million of recorded capital expenditure amounts that were approved by the CPUC in the 2020 GRC, $350 million capital expenditure amounts that were approved by the CPUC in the 2020 WMCE proceeding, and up to $843 million forecasted capital expenditure amounts approved in the 2023 GRC.
The following reflects the sensitivity of pension costs and projected benefit obligation to changes in certain actuarial assumptions: (in millions) Increase (Decrease) in Assumption Increase in 2022 Pension Costs Increase in Projected Benefit Obligation at December 31, 2022 Discount rate (0.50) % $ 5 $ 1,038 Rate of return on plan assets (0.50) % 108 — Rate of increase in compensation 0.50 % 44 207 The following reflects the sensitivity of other postretirement benefit costs and accumulated benefit obligation to changes in certain actuarial assumptions: (in millions) Increase (Decrease) in Assumption Increase in 2022 Other Postretirement Benefit Costs Increase in Accumulated Benefit Obligation at December 31, 2022 Health care cost trend rate 0.50 % $ 8 $ 38 Discount rate (0.50) % 11 81 Rate of return on plan assets (0.50) % 15 — NEW ACCOUNTING PRONOUNCEMENTS See Note 3 of the Notes to the Consolidated Financial Statements in Item 8.
The following reflects the sensitivity of pension costs and projected benefit obligation to changes in certain actuarial assumptions: (in millions) Increase (Decrease) in Assumption Increase in 2023 Pension Costs Increase in Projected Benefit Obligation at December 31, 2023 Discount rate (0.50) % $ 2 $ 1,123 Rate of return on plan assets (0.50) % 80 — Rate of increase in compensation 0.50 % 28 228 The following reflects the sensitivity of other postretirement benefit costs and accumulated benefit obligation to changes in certain actuarial assumptions: (in millions) Increase (Decrease) in Assumption Increase in 2023 Other Postretirement Benefit Costs Increase in Accumulated Benefit Obligation at December 31, 2023 Health care cost trend rate 0.50 % $ 6 $ 39 Discount rate (0.50) % 6 86 Rate of return on plan assets (0.50) % 11 — 90 NEW ACCOUNTING PRONOUNCEMENTS See Note 2 of the Notes to the Consolidated Financial Statements in Item 8.
For more information, see Note 6 of the Notes to the Consolidated Financial Statements in Item 8 below. Wildfire-Related Claims, Net of Recoveries Costs related to wildfires that impacted earnings decreased by $21 million, or 8%, in 2022 compared to 2021.
For more information, see Note 5 of the Notes to the Consolidated Financial Statements in Item 8 below. 66 Wildfire-Related Claims, Net of Recoveries Costs related to wildfires decreased by $173 million, or 73%, in 2023 compared to 2022.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

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Biggest changeITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Information responding to Item 7A is set forth under the heading “Risk Management Activities,” in MD&A in Item 7 and in Note 11: Derivatives and Note 12: Fair Value Measurements of the Notes to the Consolidated Financial Statements in Item 8. 96
Biggest changeITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Information responding to Item 7A is set forth under the heading “Risk Management Activities,” in MD&A in Item 7 and in Note 10: Derivatives and Note 11: Fair Value Measurements of the Notes to the Consolidated Financial Statements in Item 8. 91

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